The energy transition in Europe - Centre on Regulation in Europe

The energy transition in Europe: initial lessons from Germany, the UK and France Towards a low carbon European power sector Professor Natalia Fabra (Joint Academic Director, CERRE, and Universidad Carlos III, Madrid), Editor Dr Felix Christian Matthes (Öko-Institut, Berlin) Professor David Newbery (University of Cambridge) Dr Michel Colombier, Mathilde Mathieu and Andreas Rüdinger, (Institute for Sustainable Development and International Relations - IDDRI, Paris)

6 October 2015 151006_CERREStudy_EnergyTransition_Final

Centre on Regulation in Europe (CERRE) asbl Rue de l’Industrie 42 Box 16 - B-1040 Brussels - Belgium Ph.: +32 (0)2 230 83 60 - Fax: +32 (0)2 23 0 83 70

Contents About CERRE .............................................................................................................................. 5 About the authors ...................................................................................................................... 6 Executive Summary .................................................................................................................... 8 Foreword ................................................................................................................................. 10 1.

2.

Towards a low carbon European power sector, by Natalia Fabra ........................................ 12 1.1

What is the Energy Transition? ........................................................................................12

1.2

The Energy Transition: a regulatory challenge for the power sector ................................13

1.3

The Energy Transition in Germany, the UK and France: an overview................................14

1.3.1

Differences and similarities across the three countries ................................................15

1.3.2

Overview: targets and policies .....................................................................................18

1.3.3

Policies towards renewables .......................................................................................20

1.3.4

Capacity mechanisms ..................................................................................................22

1.4

Lessons from the Energy Transitions in Germany, the UK and France ..............................23

1.5

Policy recommendations: towards a low carbon power sector ........................................36

1.6

Concluding Remarks........................................................................................................46

Case Study 1: The Energy Transition in Germany, by Felix Christian Matthes ....................... 48 2.1

History, objectives and targets of the energy transition in Germany ................................48

2.2

Main policies and regulatory instruments in the power sector ........................................53

2.2.1

Introduction ................................................................................................................53

2.2.2

The remuneration scheme for power generation from renewable energy sources ......55

2.2.3

The remuneration scheme for combined heat and power production .........................60

2.2.4

The nuclear phase-out .................................................................................................62

2.2.5

Policies to enhance the efficient use of electricity .......................................................64

2.2.6

Transmission and distribution network development ..................................................65

2.2.7

The acceleration of decarbonisation in conventional power generation ......................68

2.2.8

An energy market reform? ..........................................................................................70

2.3 2.3.1

Evaluation and prospects ................................................................................................71 Greenhouse gas emissions ..........................................................................................71

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2.3.2

Electricity costs ...........................................................................................................73

2.3.3

Participation................................................................................................................76

2.3.4

Innovation ...................................................................................................................77

2.3.5

European cooperation .................................................................................................80

2.3.6

Institutional arrangements and specifics .....................................................................80

2.4 3.

Case Study 2: The Energy Transition in the UK, by David Newbery ...................................... 87 3.1

Objectives and targets of the UK energy transition ..........................................................87

3.2

Main policies and regulatory instruments in the power sector ........................................89

3.2.1

The rôle of the power sector in the energy transition ..................................................90

3.2.2

Electricity Market Reform............................................................................................92

3.2.3

Delivery of the Electricity Market Reform ....................................................................95

3.3

Evolution and prospects ................................................................................................101

3.3.1

Evolution of prices.....................................................................................................102

3.3.2

Impact on investment ...............................................................................................103

3.3.3

Distributional impacts ...............................................................................................103

3.3.4

Cooperation with neighbouring countries .................................................................104

3.4

4.

Lessons and challenges ahead .........................................................................................83

Challenges and lessons ..................................................................................................105

3.4.1

Reconciling the energy trilemma ...............................................................................105

3.4.2

Success stories and lessons .......................................................................................105

Case Study 3: The Energy Transition in France, by Michel Colombier, Mathilde Mathieu & Andreas Rüdinger.............................................................................................................106 4.1

Introduction ..................................................................................................................106

4.2

A glance at the French energy model: main characteristics and long-term objectives ....107

4.2.1

Historic evolution of energy demand .........................................................................107

4.2.2

Energy supply and electrification ...............................................................................110

4.2.3

General objectives and targets for the energy transition ...........................................114

4.3

Main policies and regulatory instruments in the power sector ......................................118

4.3.1

Long-term planning in the electricity market .............................................................119

4.3.2

The evolution of support mechanisms for renewable electricity generation ..............120


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4.3.3

The French capacity mechanism ................................................................................123

4.3.4

Power market liberalisation and European integration: the French case ....................124

4.4

Evolution and prospects ................................................................................................126

4.4.1

Compliance with targets ............................................................................................126

4.4.2

Evolution of prices and distributional issues ..............................................................127

4.4.3

Potential for regional cooperation .............................................................................130

4.5

Challenges and lessons ..................................................................................................131

References ..............................................................................................................................133 References for Chapter 1: Towards a low carbon European power sector .................................133 References for Case Study 1: The Energy Transition in Germany ...............................................136 References for Case Study 2: The Energy Transition in the UK ...................................................148 References for Case Study 3: The Energy Transition in France ...................................................151


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About CERRE Providing top quality studies and dissemination activities, the Centre on Regulation in Europe (CERRE) promotes robust and consistent regulation in Europe’s network industries. CERRE’s members are regulatory authorities and operators in those industries as well as universities. CERRE’s added value is based on: • • • •

its original, multidisciplinary and cross-sector approach; the widely acknowledged academic credentials and policy experience of its team and associated staff members; its scientific independence and impartiality; the direct relevance and timeliness of its contributions to the policy and regulatory development process applicable to network industries and the markets for their services.

CERRE's activities include contributions to the development of norms, standards and policy recommendations related to the regulation of service providers, to the specification of market rules and to improvements in the management of infrastructure in a changing political, economic, technological and social environment. CERRE’s work also aims at clarifying the respective roles of market operators, governments and regulatory authorities, as well as at strengthening the expertise of the latter, since in many Member States, regulators are part of a relatively recent profession. This study, within the framework of which this report has been prepared, has received the financial support of a number of CERRE members. As provided for in the association's by-laws, it has, however, been prepared in complete academic independence. The contents and opinions expressed in each chapter of this report reflect only the views of the chapters’ author(s) and in no way bind CERRE, the sponsors or any other members of CERRE (www.cerre.eu).


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About the authors Professor Natalia Fabra joined CERRE as a Joint Academic Director in January 2014. She is a Professor in the Economics Department of Universidad Carlos III de Madrid. She is also Research Affiliate at the Centre of Economic Policy Research in London and Associate Editor of the Journal of Industrial Economics. She edits RePEc's New Economic Papers on Regulation. In the past, Natalia has been a visiting scholar at various universities, including the University of California Energy Institute, the Institut d'Economie Industrielle (Toulouse), and Nuffield College (Oxford). Natalia works in the field of Industrial Organisation, with emphasis on Regulation and Competition Policy issues. She has worked extensively on the economic analysis of electricity markets. She holds a PhD from the European University Institute. Dr Michel Colombier is Scientific Director, and one of the founders, of IDDRI (Institut du Développement Durable et des Relations Internationales). Dr Colombier is an agricultural engineer and holds a PhD in Economics. A specialist in energy policy and climate issues, he has served as a member of the scientific panels of the Global Environment Facility (GEF) and the French Global Environment Fund (FGEF). Having worked at the Centro de Estudos de Economia, Energia, Transportes e Ambiente (CEEETA) at the University of Lisbon, he joined l’Agence de l'environnement et de la maîtrise de l'énergie (ADEME), a French government body charged with promoting environmental protection energy efficiency and renewable energy. Dr Felix Christian Matthes is Research Coordinator, Energy & Climate Policy at the Öko-Institut – Institute for Applied Ecology in Berlin. He is the author of numerous studies and publications on German and international energy, environmental and climate policy. Key topics of his research include decarbonisation strategies for Germany and the European Union, EU energy market development and market liberalisation, energy and emissions projections as well as greenhouse gas emissions trading. Dr Matthes is a member of the Advisory Group to the European Commission on the Energy Roadmap 2050 and has also served as a scientific member of the German Bundestag’s Study Commission on Sustainable Energy. From 2007 – 2008 he was a visiting scientist at the Massachusetts Institute of Technology. Dr Matthes graduated as Diplom-Ingenieur from Leipzig University of Technology and holds a PhD in political science from the Free University of Berlin. Mathilde Mathieu joined IDDRI (Institut du Développement Durable et des Relations Internationales) in 2013 as a researcher, where she has conducted a comparative analysis of national energy transition scenarios and is currently working on European energy and climate policies. After completing her studies as an electrical engineer at the National Institute of Applied Sciences (INSA) in Lyon in 2011, she worked in the field of energy within Areva. In 2012, she obtained a Master’s in Public Policy and Environmental Strategy from AgroParisTech-ENGREF. She has also spent time at the Politécnico di Torino (2008) and at the Instituto Tecnológico de Buenos Aires.


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Professor David Newbery is Research Director of the Cambridge Energy Policy Research Group, Emeritus Professor of Applied Economics at the University of Cambridge, and a Research Fellow in the Control and Power Research Group at Imperial College London. He is a Fellow of the British Academy and of the Econometric Society. He was the 2013 President of the International Association for Energy Economics. Educated at Cambridge with degrees in Mathematics and Economics, he has managed research projects on utility privatisation and regulation, electricity restructuring and market design, transmission access pricing and has active research on market integration, transmission planning and finance, climate change policies, and the design of energy policy and energy taxation. Occasional economic advisor to Ofgem, Ofwat, and ORR, former member of the Competition Commission and chairman of the Dutch Electricity Market Surveillance Committee, he is currently a panel member of Ofgem’s Network Innovation Competition, a member of the Panel of Technical Experts offering quality assurance to DECC on the delivery of the UK’s Electricity Market Reform and the Deputy Independent Member of the Single Electricity Market Committee of the island of Ireland. Andreas Rüdinger is a Research Fellow at IDDRI (Institut du Développement Durable et des Relations Internationales), specialised in energy and climate policies. He currently leads several projects on the European electricity market and national energy transition strategies. His work focuses on the development and integration of renewable energies and energy efficiency policies. He has published several comparative studies on energy policies in France and Germany. Andreas completed his Master's degree in political sciences at Sciences Po Bordeaux and the University of Stuttgart, Germany.


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Executive Summary The Energy Transition is the set of policies and structural changes aimed at decarbonising the economy. Germany, the United Kingdom and France have taken the lead in implementing national policies to facilitate the Energy Transition. All three countries have set out a range of ambitious targets and policies to cut emissions, deploy renewable resources, and improve energy efficiency: the Energiewende in Germany, the Carbon Plan and the Electricity Market Reform in the UK, and the Loi sur la transition énergétique pour la croissance verte in France. With the Paris summit in the background, their experiences show that Europe can contribute to the global fight against climate change by putting in place climate and energy policies from which other countries or regions can learn. In this CERRE study, we review the early experiences of these three countries with the aim of providing practical guidance. Even though the Energy Transition encompasses several sectors of the economy, we focus on the power sector given its relevance for decarbonising the whole economy. First, the power sector comprises the largest source of greenhouse gas emissions. And second, there is ample scope to reduce them through the use of renewable resources, coupled with other low carbon intensive options during the transition period. The experience in Germany, the United Kingdom and France shows that the Energy Transition is a lengthy process that requires strong political support, not least because of the often conflicting interests that arise when technologies, social norms, and institutions change. The new technologies have triggered the entry of new market players, which in turn has created an environment favourable to R&D. Participation of a wider range of actors has also proved to be key in securing broader public acceptance towards climate policies. In turn, as financial markets start to factor in the impact of climate policies, some corporations are also starting to change their policies. This should prove decisive to push the Energy Transition forward. The Energy Transition has put extra pressure on electricity bills. Concerns over the increase in energy costs have led governments to water-down some climate policies. Notwithstanding the high cost of the low carbon investments, this pressure has also been driven by (i) an unbalanced burden share of the costs among the various consumer groups, and (ii) the surge of rents and inefficient costs associated with the implementation of certain climate policies. For the future, it is expected that the Energy Transition will deliver lower costs due to the increased maturity of renewables, the improvements in energy efficiency, and their associated externalities. The cost reductions achieved by renewables have exceeded all expectations. Part of the success lies in the early roll out of renewables, which rested on technology-specific Feed-in-Tariffs (FiTs). This system has been key in driving R&D efforts in a context in which the EU carbon market has delivered a weak and volatile price signal. However, the FiT system failed to adjust the tariffs in line with cost reductions, not allowing consumers to fully benefit from them. 151006_CERREStudy_EnergyTransition_Final

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The renewable rollout has brought new challenges, such as the need to promote investments in flexible back-up plants. Countries have tried to address this issue in an uncoordinated fashion, which has resulted in a patchwork of different types of capacity mechanisms. The Energy Transition is faced with large and diverse risks, some of which are unavoidable - both for firms as well as for consumers. Regulation should thus seek to allocate these costs in an efficient manner so as to minimise overall costs. We believe this calls for the use by regulators of long-term contracts for the new investments (both in renewables and in back-up capacity), as the reduced risk exposure for investors should translate into lower risk premia. If there is adequate competition among potential investors, auctions for long-term contracts would enable the passing on of these lower premia to consumers. In turn, competition through auctions would also reflect the rapid cost reductions as renewable resources approach maturity. This virtuous cycle would be reinforced by reduced regulatory uncertainty, as long-term contracts are less vulnerable to regulatory opportunism as compared to other remuneration schemes. Nevertheless, it is important to stress that long-term contracts are not a substitute but rather a complement of liquid wholesale markets. Indeed, liquid wholesale markets are still needed to facilitate an efficient dispatch and to provide hedging opportunities, while long-term contracts minimise firm’s incentives to exercise market power in these markets. The Energy Transition requires that firms undertake investments in capital-intensive assets with high upfront costs. Evidence has shown that the current regulatory arrangements in power markets are not well suited to induce such investments, not least to set prices in renewables-dominated systems. Good regulations are forward looking: given that low carbon assets are long-lived, it is paramount to already set out the regulatory framework that will be in place both in the short as well as in the medium- to long-run. While there are different views in the regulatory debate – as will most likely be shown by the recent public consultation launched by the European Commission on this issue - we believe that a future-proof electricity market should rest on three pillars: • • •

Competition in the market should be progressively replaced by competition for the market, i.e., through capacity tenders run by (or on behalf) of regulators; Long-term Contracts for Differences for renewables and for back-up capacity, (referenced to the spot energy price), should be used by regulators to de-risk investments, and A liquid wholesale energy market should be preserved.

In sum, national governments should commit to supporting the Energy Transition with no further delay. This involves putting in place targets and policies leading to an almost carbon-free power sector by 2050. Europe’s climate and energy policies are an important complement, but not a substitute for national policies in this area. To avoid damaging investors’ confidence, governments should commit to regulatory stability. This is not in contradiction with the need to have rules that evolve during the transition period as long as the course of changes is clearly set and announced in advance. The road ahead is long and windy, but the stakes are high.


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Foreword The proximity of the Paris summit is building up momentum for climate action. Experts repeatedly warn that atmospheric concentrations of carbon dioxide have to be constrained below 400 ppm to avoid an increase in global warming above 2°C. Yet, this concentration, which was first reached in May 2013, has already been exceeded.1 As governments seek to strike a global climate agreement at the end of the year, very few now argue against the urgent need to decarbonise our economies. Europe has traditionally led the efforts to tackle climate change. The 2030 climate and energy package2 released in 2014 commits Europe to reducing greenhouse gas emissions by 40% as compared to 1990 levels, to increasing the EU-wide weight of renewables on final energy consumption to 27%, and to improving energy efficiency up to 27% by 2030. The most recent Energy Union package3 further reiterates Europe’s commitment towards the achievement of environmental objectives, as it advocates for “a resilient Energy Union with an ambitious energy policy at its core”. Europe also aims at becoming the “most energy efficient economy in the world” as well as “number one in renewables”. Nevertheless, Europe’s decreased relevance in the worldwide political arena casts doubts as to whether Europe’s climate commitments will be enough to encourage other relevant actors to follow suit. There is, however, one area in which Europe’s contribution can be crucial. Committing to ambitious climate targets is paramount, but designing and implementing policies capable of achieving those targets is equally important. There is no magic recipe, nor a single solution for all countries or regions, or for all stages of the decarbonisation process. However, policy experience in Europe can provide important lessons for other countries as they seek to decarbonise their economies. This can indeed be Europe’s main contribution to the fight against climate change. Several European countries – including Germany, the UK and France –have implemented new regulatory instruments to facilitate the transition to a low carbon economy. In this CERRE study, we review their early experiences with the aim of providing practical guidance for other countries and regions. Even though the low carbon transition encompasses several sectors of the economy, the focus will be put on the power sector given its relevance for decarbonising the whole economy. The study is structured in four chapters. The first chapter (authored by Natalia Fabra) contains an overview of the experiences and main policies implemented in Germany, the UK and France. These experiences provide lessons and allow for the drawing of regulatory suggestions that can be useful for other countries and regions as they seek to achieve a least-cost Energy Transition. The 1

In May 2015, the Mauna Loa observatory (which provides the most reliable recordings of carbon concentrations) reported carbon concentrations of 404 ppm. See Fowlie (2013). 2 http://ec.europa.eu/clima/policies/2030/index_en.htm 3 http://ec.europa.eu/priorities/energy-union/index_en.htm


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remaining three chapters of this study provide an in-depth description of the Energy Transitions in Germany (authored by Felix Matthes), the United Kingdom (authored by David Newbery) and France (co-authored by Andreas Rüdinger, Michel Colombier, and Mathilde Mathieu).


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1. Towards a low carbon European power sector, by Natalia Fabra 1.1 What is the Energy Transition? All goods and services contain energy. When energy is generated through the combustion of fossil fuels, energy consumption generates carbon emissions. Hence, in order to decarbonise our economies, we have (i) to become more energy efficient in order to reduce the energy content of goods and services; and (ii) to rely more heavily on low-carbon energy sources in order to reduce the carbon intensity of the energy consumed. It is thus not surprising that the set of policies and structural changes needed to drastically cut greenhouse gas emissions has received the name of “Energy Transition”. The Energy Transition is brought about by policy changes and structural changes that take place over a long, and often non-linear, process. In the power sector, these changes encompass massive investments in low carbon assets and infrastructures, as well as new market rules and regulatory arrangements for governing the process. There have been several energy transitions throughout history, including the shift from biomass to coal that took place during the Industrial Revolution, or the shift from coal to oil that took place during the twentieth century. However, the distinctive feature of the current Energy Transition is that it encompasses a combination of various – and not just one at a time - politically-driven changes. For instance, decarbonisation in Europe would be unlikely without the political commitments embodied in the EU climate and energy policy, for the same reasons that the Energy Transitions in Germany, the UK and France have mainly been driven by political decisions. The Energy Transition in the power sector has brought about changes in corporate structures as new actors have entered the sector, from innovative medium-sized companies to citizens who start producing electricity through small-scale investments in renewables. These changes have already contributed towards the fragmentation of the market structure, leading to a surge of more diverse views in the regulatory debate. Among the various challenges faced by the Energy Transition, the distributional impacts of the various policies are likely to be paramount as these ultimately affect the public acceptance of such policies and thus their political support. It is beyond dispute that the market arrangements and regulatory policies that are put in place to facilitate the Energy Transition should be efficient. However, the efficiency of such policies cannot be disentangled from their distributional impacts: the most efficient option will not succeed without societal support. Similarly, the success of the Energy Transition requires irreversible commitments in support of the policies. Otherwise, the often conflicting interests that arise may delay or hamper policy


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implementation. Indeed, policy making in Europe has been subject to pressure by some lobby groups, essentially because low carbon policies reduce the profitability of some of the existing power generation assets.4 In the power sector, renewables depress wholesale electricity prices and reduce the market share of fossil fuels while, more broadly, some high carbon assets become stranded as a consequence of the climate and energy policies.5 The Energy Transition is widely seen as a lever for R&D intensive growth.6 As such, it constitutes an opportunity for modernising our economies. As renewable energies are likely to be massively deployed in other parts of the world, early action might allow the European industry to gain and maintain a competitive advantage in this area. The technological spillovers triggered by R&D in low carbon resources may further benefit other sectors of the economy. Concerns remain as to the macroeconomic effects of the Energy Transition, as the need to recover the costs of the low carbon policies put pressure on electricity bills. However, despite the likely rise in energy prices in the short run, the Energy Transition is seen as leverage for competitiveness in the medium to long run as the increased maturity of renewables and energy efficiency investments give rise to future reductions in energy costs.

1.2 The Energy Transition: a regulatory challenge for the power sector In order to move towards a low carbon economy, all activities - including power generation, transport and heating, among others -must drastically reduce their emissions. For this to be possible, action must come first and foremost from the power sector. The reason is two-fold. First, the power sector comprises the largest source of greenhouse gas emissions. And second, there is ample scope to reduce them through the use of renewable resources, coupled with other low carbon intensive options during the transition period. Decarbonising other sectors is more challenging, as these typically lack the ability to incorporate renewables into their production processes. There will thus be an increased use of electricity in a wide range of sectors, which will have to be at least partly compensated with improvements in energy efficiency. The 2050 Energy Roadmap for moving to a competitive low carbon economy states that the EU should be prepared to reduce its domestic emissions by 80% in 2050, as compared to 1990. The achievement of this goal thus requires almost full decarbonisation of the power sector. It is beyond 4

See Euroactiv, 11 October 2013 “Energy CEOs call for end to renewable subsidies”. see John Stern’s (2013) report on the carbon bubble; the OCDE and the IEA have also expressed similar concerns 6 The current EU Commissioner for Climate Action and Energy recently argued that: “We have three times more renewable power per capita in Europe than anywhere else in the rest of the world. We have more than one million people working in a renewable energy sector worth over €130 bn a year and we export €35 bn worth of renewables every year." (Renewable energy progress report, Press release, 16 June 2015). See also the report written by the German Ministry of the Environment (2010). 5


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dispute that the energy sector will have to go through a profound transformation as Europe seeks to achieve this goal. While the Energy Transition is faced with diverse challenges (technical feasibilities, macroeconomic costs, affordability in general or security of supply issues) the most significant challenges result from the regulatory and market arrangements as well as from the distributional impacts of the policies. The energy trilemma, i.e., the triple challenge of making energy supplies sustainable, secure and affordable, is at the heart of the Energy Transition. The energy trilemma has headed Europe’s climate and energy policy for the last decade, at least since the European Commission committed in 2007 to the 20-20-20 objectives with the aim of “combating climate change, increasing the EU’s energy security and strengthening its competitiveness.” The recently approved Energy Union package reiterates Europe’s commitment to this triple objective as it sets out a “resilient Energy Union with an ambitious energy policy at its core” as an instrument to “give EU consumers secure, sustainable, competitive and affordable energy”. Yet, even though the policy objectives are clear, their actual policy translation is far from straightforward. How can countries find the right balance between the sustainability, security of supply and affordability objectives? Which are the best available policy options to achieve them? The answer is certainly not easy. Most likely, there is no single correct answer. Experience tells us that one size does not fit all: answers differ because countries differ in their energy mixes, availability of natural resources, public acceptance and political support for the various policy options, or because they are at different stages of the Energy Transition process. This does not mean that one cannot find common lessons. Rather, the various solutions adopted across countries provide an array of valuable lessons for all. The early experiences of Germany, the UK and France – with their national idiosyncrasies – show that this is already the case, as we elaborate next.

1.3 The Energy Transition in Germany, the UK and France: an overview Germany, the United Kingdom and France have taken the lead in implementing national policies to facilitate the Energy Transition. All three countries have set out a range of ambitious targets and policies to cut emissions and decarbonise their power sectors. It is difficult to overstate the importance of the power sectors in these three countries. Germany, the UK and France have the three largest power sectors in Europe, together representing almost half of total electricity produced and consumed in the European Union. According to the latest Eurostat statistics, 7 annual net electricity generation in Germany is the highest in Europe, accounting for 19.2 % of the EU-28 total, just ahead of France (17.7 %) and the UK (11.0 %). Indeed, these three countries are the only Member States with a double-digit share. Their importance

7

http://appsso.eurostat.ec.europa.eu/nui/show.do?dataset=nrg_105a&lang=en


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spreads beyond these figures: since these countries are heavily interconnected with other European countries - particularly so in the case of Germany and France-8 whatever happens in these three countries affects its neighbours. Table 1: Key indicators (2014 data)

Net Generating Capacity GW of which Nuclear GW of which Fossil Fuels GW of which Renewable GW of which Hydro GW Net Generation TWh Balance Imports- Exports TWh

Germany 189,5 12,1 85,3 81,5 10,7 548,5 -35,7

UK 74,9 97,5 53,3 7,9 4,0 363,6 19,5

France 128,9 63,1 24,4 16,0 25,4 541,2 -65,8

Source: ENTSO-E (2015)

1.3.1 Differences and similarities across the three countries Germany, the UK and France have similarities among them, but also important differences. Among others, they have different initial conditions (regarding e.g. their energy mix), different institutions or governance structures (regarding e.g. the role of independent regulators), different market structures in the power sector (both horizontally and vertically), and their societies have shown different attitudes towards the various energy policy options (regarding e.g. the renewable rollout, or the role of nuclear). These differences have affected the choice and the success of policies towards the Energy Transition. First, these three countries differ in their energy mixes. France sources the largest share of its generation from nuclear, with 75%, while Germany and the UK have the largest shares of coal in the generation mix, with 44% and 39% respectively. This implies that the carbon intensity of France is much lower than in the other two countries. Paradoxically, this favourable initial condition has made the implementation of the Energy Transition policies in France harder, as it has required a more convincing narrative to justify the diversification of energy sources towards renewables. In contrast, the high carbon intensities in Germany and the UK have been powerful drivers for pushing for ambitious energy efficiency and renewables targets. Nevertheless, the gradual phase out of polluting power stations in Germany and the UK has added complexity to the decarbonisation of their power sectors. For instance, subsidies for the use of domestic hard coal in Germany will not be phased out until 2018. After several months of 8

Germany is interconnected with Austria, Switzerland, the Czech Republic, Denmark, France, Luxembourg, the Netherlands, Poland, and Sweden. France is interconnected with Belgium, Germany, the UK, Spain, Italy and Switzerland. The UK in connected to France, Ireland and the Netherlands.


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discussions, Germany has recently abandoned its plans for a tax on coal-fired power plants.9 In the UK, the recently held capacity auction has awarded capacity payments to two-thirds of the UK's coal plants, making it easier for them to remain open for longer. Whereas all three countries have favoured the expansion of renewable energy, they differ in their policies towards nuclear. On the one hand, Germany has decided to phase out nuclear (the last nuclear reactor will shut down by 2022), and France has decided to gradually reduce the weight of nuclear (by 2025 nuclear will represent 50% of total production in the power sector, down from the current 70%). On the other hand, the UK has decided to construct a new nuclear reactor. Second, there are important differences in the market structure and regulatory arrangements in place in the power sectors in Germany, the UK and France. The French electricity market is dominated by a large company, EDF, which is under public control and close regulatory scrutiny. In contrast, the power sectors in Germany and the UK are more fragmented, and currently less subject to public intervention. Also, all three countries have traditionally followed public policies to protect their industrial sectors, using exemptions to mitigate the effects of increasing electricity prices on energy-intensive consumers. Third, there are substantial differences in the electricity prices paid by households and industrial consumers across the three countries. While Germany has one of the highest electricity prices in Europe, electricity prices in the UK are in the median range, and prices in France are relatively lower. One reason for the low prices in France is that retail prices remain largely regulated, despite the fact that the opening of retail choice dates back to 2007. In 2010, the French government passed the NOME law that eliminates regulated tariffs for industrial consumers but maintains them for households. However, in an attempt to facilitate retail competition, the NOME law makes approximately 25% of EDF’s nuclear production available to alternative suppliers at the AREHN tariff, currently set at 42.5€/MWh. This Law might have contributed to keeping retail prices low for French consumers (Creti et al., 2013). Nevertheless, the energy regulator CRE estimates that residential bills could rise by as much as 30% in the next two years, unless this is reversed by political decisions.10

9

Instead, the equivalent of 2.7 GWs of brown coal-fired plants will be taken as reserve power in case of emergency. A summary of the public debate regarding the implementation of the so-called Climate Levy can be found here https://www.cleanenergywire.org/news/climate-levy-debate-and-proposals-cutting-co2emissions 10 Very recently, in July 2015, the French government has decided to cap price increases at 2.5% from August, below the 3.5%-8% range that the energy regulator CRE had recommended.


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Table 2: Electricity prices

Electricity prices (Domestic) over EU28 average Electricity prices (Industrial) over EU28 average

Germany 144,7% 125,3%

UK 88,3% 113,6%

France 74,5% 79,1%

Source: Eurostat

These price differences have given rise to countervailing incentives. On the one hand, the high electricity prices in Germany have provided a stimulus for energy efficiency improvements, which has been absent in the French case. On the other hand, when prices are high, it is less politically feasible to increase bills. In Germany, for instance, the increase in the renewables surcharge led the government to exempt some industrial consumers from paying it, which in turn caused further increases in the surcharge paid by those consumers who were not exempted (typically, households and small businesses). Had these exemptions not taken place, prices to households would not have risen as much as they have. In turn, this would have muted part of the criticisms about the costs of the Energy Transition in Germany.11 Despite this, German society strongly supports the Energy Transition in ways that could probably not be expected elsewhere. In the UK, the increase in electricity prices has led to strong pressure to end renewable support.12 Indeed, in June 2015, the UK government decided to end support for onshore wind a year earlier than expected. Fourth, the three countries have important differences in their institutional and governance structures. This has had an important impact on the policies adopted as well as on the process of implementation. For instance, unlike other European member states, the UK has a long tradition of independent regulators, which further consult with committees of independent experts. This might explain why, in the UK case, the energy regulator Ofgem has played a decisive role in the Energy Transition. Indeed, in 2009, Ofgem took the initiative of launching Project Discovery, a sector inquiry that eventually gave rise to the Electricity Market Reform. Furthermore, climate and energy related policies are regularly reviewed by various panels of independent experts, such as the Committee on Climate Change or the Panel of Technical Experts on the Electricity Market Reform, among others.13In contrast, the role of independent regulatory and advisory boards has been more limited in other member states, including Germany and France, as compared to the UK.

11

See for instance the Spiegel Online International article “Germany's Energy Poverty: How Electricity Became a Luxury Good”, available at http://www.spiegel.de/international/germany/high-costs-and-errors-of-germantransition-to-renewable-energy-a-920288.html 12 The price increases have also raised concerns about the exercise of market power by the big six electricity companies. Indeed, in June 2014, the UK’s big six energy companies have been formally referred to the Competition and Markets Authority for a full investigation. 13 See http://www.theccc.org.uk and https://www.gov.uk/government/groups/electricity-market-reformpanel-of-technical-experts, respectively.


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Some of these differences partly explain differences in the policies chosen. Before moving to the lessons that can be drawn from these country experiences, we briefly outline below the evolution of the low carbon policies in each of these countries.14

1.3.2 Overview: targets and policies Germany has been a precursor of the Energy Transition in Europe. Even though the name given to it, Energiewende, was officially coined in 2011, it has been used since the early 1980s when the energy and climate policy debate first started. Discussions regarding the Energy Transition still occupy a prominent space in the Germany policy agenda nowadays. The early debates about the role of nuclear power, together with the search for alternatives, shifted the focus towards the need to invest in energy efficiency and renewables. The first target for the reduction in carbon emissions dates back to 1990, when the German government committed to reducing them by 25% by 2005 as compared to 1987 levels. This target was subsequently strengthened on several occasions. The current objective is to reduce greenhouse gas emissions by 40% by 2020, 50% by 2030 and 80-95% by 2050, as compared to 1990 levels. Probably as importantly, these ambitious emissions reductions targets have been accompanied by a set of policies - notably, the nuclear phase-out decision, the Feed-in Tariff (FiT) system to allow for the renewable energy rollout, and the currently debated Climate Levy that will eventually lead to the gradual phase out of old coal plants. These measures have been coupled with a set of targets for renewables and sector-specific energy efficiency improvements. Germany has decided not to create a capacity system. In the UK, a carbon target was first set explicitly in 1990, with the commitment to reduce carbon emissions to 1990 levels by 2005. The government also imposed a Fossil Fuel Levy on fossil fuel generation to raise funds to pay for nuclear decommissioning. It also placed a Non-Fossil Fuel Obligation (NoFFO) on electricity suppliers, who were required to buy a certain amount of nuclear or renewable electricity at a premium price. Interestingly, some of the NoFFO funds were used to procure renewables through competitive tenders, which resulted in dramatic falls in the cost of renewables. Since then, energy and climate policy has largely evolved, with targets becoming more stringent, and policy changes facilitating the achievement of those goals. The UK is committed to a series of five-yearly carbon budgets to allow the achievement of its 2050 target,15namely to reduce emissions by at least 80% below 1990 levels. The UK is currently in the second carbon budget 14

Chapters 2 to 4 of this study contain a more detailed description and in-depth analysis of the policies implemented in each country. 15 http://www.theccc.org.uk/tackling-climate-change/reducing-carbon-emissions/carbon-budgets-andtargets/


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period (2013-2017), during which emissions have to be reduced by 29%. The fourth carbon budget (2023-2027) requires that emissions be reduced by 50% on 1990 levels by 2025. The 8% emissions reductions achieved during 2014 put the UK 36% below 1990 levels, well on track to achieve its targets.16 Furthermore, despite some controversies, the government has recently announced that the UK has just met its interim renewable energy target for 2013/14, in compliance with the interim objectives set by the EU Renewable Energies Directive. Importantly, the UK has accompanied these environmental targets with a deep reform of its power market (known as the Electricity Market Reform). Current policy incorporates four main ingredients: a Carbon Price Floor to avoid extremely low carbon prices; Contracts for Differences (CfDs) to incentivise the deployment of low carbon resources (nuclear and renewables); a Capacity Market to address concerns over security of supply; and an Emissions Performance Standard (EPS) that limits emissions from new power stations. In France, a comprehensive debate about the Energy Transition as a whole did not start until 2012, even though previous initiatives existed regarding specific issues, e.g. those triggered by the EU directives (mainly, the 2008 package), the Grenelle process launched in 2007, or the 2010 POPE law that included the objective of reducing greenhouse gas emissions by 75% in 2050. One of the reasons for this delay, relative to the German and UK experiences, is probably the fact that the French power sector already has some of the lowest carbon emissions, due to its reliance on nuclear power. However, emission reductions in other sectors of the economy lag behind, and there is ample scope to reduce energy consumption through improvements in energy efficiency. Also, the deployment of renewable energies has been rather slow, and it is unclear whether France will meet its 2020 renewables target (the current weight of renewables is 14.2%, still far from the 23% objective). In July 2015, the French National Assembly has given the final approval of the Law on the energy transition for green growth containing a long-term project to achieve ambitious objectives for emissions reductions, renewables and energy savings for 2020, 2030 and 2050. By 2050, emissions will have to be 75% lower than in 1990, and energy consumption has to decrease by one half with respect to 2012. By 2030, the share of renewables has to reach 32% as a share of final energy consumption, and 40% as a share of total electricity produced. This is coupled with a commitment to gradually reduce the weight of nuclear power in generation, down from the current 75% to 50% by 2025. Interestingly, France has incorporated an explicit target for fossil fuel consumption in 2030, which has to reduce 30% below 2012 levels. Inspired by the example of the UK, France will also implement a national low carbon strategy through binding carbon budgets for different sectors. 16

However, a recent report by the Committee on Climate Change (CCC) casts doubts as to whether these reductions can be sustained in the long term, and calls the government to strengthen its ongoing efforts to reduce emissions.


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In order to achieve these targets, France has put in place support instruments for renewable energies and energy efficiency. There is an FiT system in place for renewable technologies (together with other instruments), and the plan is to move gradually towards a system of competitive tenders. As for energy efficiency, the government has launched a vast program for renovating 400,000 buildings per year between 2013 and 2020, plus the renovation of 800,000 social houses by 2020. In 2006 France also put in place a system of white certificates for energy efficiency. The energy savings achieved during the period 2006-2014 have exceeded the targets. France will put in place a decentralised capacity market.

1.3.3 Policies towards renewables In Germany, the renewable energy roll out was heavily supported by the use of Feed-in-Tariffs (FiTs). The first FiTs, introduced in 1990, were complemented by technology-specific incentive programmes. This initial scheme was reformed in subsequent rounds, with adjustments of the tariffs for different types of technologies. The 2000 reform introduced a system by which the tariff for solar PV was made dependent on the PV capacity expansion during the previous year. The period 2009-2012 witnessed a large increase in the cost of the FiT system following the boom of solar PV and the rapid decline of wholesale prices (in part driven by the expansion of renewables, but also by the reduction in carbon and fossil fuel prices). This, coupled with the exemption given to industrial consumers, implied rapid increases in the renewable surcharge paid by residential consumers. The EU Guidelines on State Aid for Environmental Protection and Energy 2014-2020 (EEAG)17 triggered a change in the regulation of renewables in Germany. Under the current regulation, new renewable installations have to sell their power to the market, and they receive a premium, which is computed as the difference between a technology-specific strike price and the average wholesale market price. Also, roll-out corridors have been set for wind, solar PV, and biomass. If the capacity of these technologies falls outside the corridors, the technology-specific strike prices for the new installations are adjusted upwards or downwards. France mimicked the German FiT system, but failed to reproduce one of its key characteristics: long term stability. Instead France has quite a history of stop-and-go policies, notably on solar PV and onshore wind tariffs and regulation. Electricity from renewable sources is currently promoted through an FiT system that requires electricity distributors to purchase renewable electricity at administratively set prices for the various technologies. In contrast to the German and French policies, the UK has instead resorted to various alternative instruments: auctions for what were effectively FiTs were first used in 1990; these were replaced by 17

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52014XC0628(01)&from=EN


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a system of Renewable Obligation Certificates (ROCs), which have in turn been replaced by the allocation of Contracts for Differences (CfDs) through auctions. Whereas the auctions that were held in the early 90s proved very effective in pushing down the costs for renewables, they failed in designing the penalties for non-delivery. Indeed, the falling success rate of the contracted renewables led to a rethink of the system, which was subsequently substituted by the system of ROCs. Under this system, energy suppliers had the obligation to source an increasing share of their power from renewables, and they could do so by acquiring certificates. Renewable installations would thus earn the wholesale market price plus the value of the certificates. An initial technologyneutral approach was replaced by a technology-specific approach, as different technologies received different amounts of certificates per MWh. Still, since the ROC system established the same remuneration regardless of location, it gave rise to excessive payments for installations in particularly windy locations. Furthermore, the price of certificates was too volatile and too sensitive to policy intervention.18 The Electricity Market Reform recently implemented in the UK has incorporated long-term 15-year Contracts for Differences for low-carbon investments. The CfD specifies a strike price and pays or receives the value of the strike price less a reference market price. Thus, CfDs are essentially like FiTs, with an important difference: unlike in a FiT, the CfD holder is responsible for selling its output to the market, including the responsibility to manage and pay for imbalances. Hence, generators under a CfD are effectively paid less than the strike price as they have to bear the costs associated with balancing renewables, much of which is intermittent. Auctions are now used to set the strike prices of the CfDs. Renewable technologies are divided in two different pots depending on their degree of maturity.19 Developers compete by submitting sealed bids to each pot, which are chosen as a function of the strike price regardless of the delivery date or the specific technology within each pot. The allocation of CfDs continues from low to high strike prices until the entire budget allocated to the pot has been used up. Hence, if investors offer lower prices, the total amount of renewable capacity that gets installed goes up. The total budget for each round of auctions is fixed, with all rounds not exceeding £7.5 billion annually by 2020. The first auction, which was held in December 2014, was very successful in pushing the costs of renewables substantially below the former strike prices. However, and despite 18

The ROC was due to close on 31 March 2017, with a three-year period of overlap with the Contracts for Difference (CfDs) scheme that started operating in 2014. However, the UK government has recently announced that the ROC system will close to onshore wind farms a year earlier than originally expected. However, ROC support will be continued for projects that have already secured planning permission, a grid connection and land rights. 19 There is a group of ‘established’ technologies (onshore wind (>5 MW), solar photovoltaic (>5MW), energy from waste with CHP, hydro (>5MW and 5MW), dedicated biomass with CHP and geothermal).


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the early experience of the NoFFO auctions, penalties for non-delivery have not stopped two solar farms from dropping out after winning a slot at very low strike prices.

1.3.4 Capacity mechanisms In the UK, a Capacity Auction has been introduced following the US experience (Newbery and Grubb, 2014). In the auction, that takes place once a year, both existing assets as well as new installations participate to make their capacities available in exchange for capacity payments. The amount of capacity to be procured, which is set by the government following the advice of the System Operator, enters the auction through a downward sloping schedule.20 If successful, new entrants are granted 15 year contracts for indexed capacity payments, which add up to their energy market revenues. Existing plants act as price-takers. If successful, they receive the clearing price and a one-year contract to guide exit decisions. Demand Side Response can also compete in the auction for one year contracts. The first capacity auction was held in December 2014, and it has delivered a £19.40/kWyr price, well below expectations. A completely different capacity mechanism will be used in France. Rather than opting for a centralised system, the French have favoured a decentralised capacity system much closer to the Renewables Obligation Certificate system that the UK used to incentivise renewables. The French capacity system obliges energy suppliers to contract enough capacity to cover the peaks of their customers’ demand. Capacity certificates can be bought from the capacity owners, or from operators aggregating large industrial consumers capable of providing demand response. Certificates will be traded bilaterally, but it is expected that an exchange platform will be created as well. A critical ingredient is the design of penalties for those suppliers who fail to buy enough certificates. In contrast to these two experiences, Germany has opposed the existing and planned reserve mechanisms. In particular, its Energy Minister came out publicly against capacity markets, under the belief that “a functioning electricity market requires real scarcity prices. They send the necessary investment signals.”21

20

At the cost of new entry, estimated by the regulator at £49/kWyr, the demand schedule hits the exact amount that the government wants to procure. 21 http://www.euractiv.com/sections/energy/gabriel-rejects-senseless-calls-surplus-energy-capacity-311433


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1.4 Lessons from the Energy Transitions in Germany, the UK and France In this section we summarise the main lessons that can be drawn from the experiences in Germany, the UK and France. These lessons allow us to highlight some policy recommendations aimed at facilitating the achievement of the Energy Transition at least cost. We have grouped the early lessons from the experiences in Germany, the United Kingdom and France as follows: 1. The Energy Transition is a long process that requires strong political support. The countries that have taken the lead in implementing the reforms have incurred higher costs, but have also enjoyed a first-mover advantage. 2. European climate and energy policy has bolstered national policies, but more progress is needed in certain areas, including carbon pricing and market integration. 3. The Energy Transition has put extra pressure on electricity bills. This reflects the increase in the costs due to the low carbon policies, but also an unbalanced burden share of the costs among the various consumer groups. In turn, concerns over the increase in energy costs have led governments to water-down some climate policies. 4. The ETS has delivered a weak carbon price signal. Countries have had to strengthen it by adding additional mechanisms. Carbon pricing policies at the national level are politically challenging. 5. Renewable energies have played a prominent role in the Energy Transition. Their costs have gone down beyond expectations. 6. The success of the early roll out of renewables rested on technology-specific Feed-in-Tariffs (FiTs). However, the FiT system broadly failed to adjust the tariffs in line with cost reductions, and in controlling total investment. 7. The existing market arrangements have failed to promote efficient investments in generation capacity. Countries have tried to address this issue in an uncoordinated fashion. 8. R&D in low cost technologies has played an important role. Both the climate policies as well as the increase in public expenditure have been important drivers of R&D and cost reductions. 9. Efforts in promoting energy efficiency have been weak. There is mixed evidence concerning the potential of some of these policies to reduce energy consumption. Below, we provide a more detailed description of the lessons outlined above.


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1. The Energy Transition is a long process that requires strong political support. The countries that have taken the lead in implementing the reforms have incurred higher costs, but have also enjoyed a first-mover advantage. The Energy Transition is a lengthy process. Germany, the UK and France took the lead in implementing national climate policies and still they have a long road ahead towards decarbonisation. Their experiences show that the structural changes needed to trigger changes in consumption and production patterns take time, and that the deployment of infrastructure involves lengthy processes. Furthermore, often conflicting interests further delay the implementation of the reforms. In light of the long term dimension of the Energy Transition, there is a need for adequate long term policy planning. Policies have to be stable so as to reduce investors’ risk premia, while at the same time being able to deal with the major uncertainties that are linked to a transition that spreads over several decades. It is a contentious issue whether early policy implementation provides a competitive advantage or disadvantage. The German experience illustrates the trade-offs. On one hand, it has been costly for Germany to be one of the first movers of the Energy Transition. An important fraction of the low carbon investments were carried out when the technology was not mature. Indeed, the externalities generated by the German renewable energy rollout have allowed other countries to benefit from lower investment costs. For instance, the costs of solar PV modules have dropped 80% in the last 5 years, in part (though not only) due to the strong demand induced by the German renewables policy. However, Germany has also benefited from a first mover advantage in several other dimensions. In Germany, there have traditionally existed strong links between industrial policy and energy policy, and the Energiewende has been no exception. The German green industry is nowadays among the most advanced ones in the world, 22 owing significantly to the domestic environmental policies that have contributed to building a robust manufacturing sector. German industry has also benefitted from low energy prices, partly driven by the price-depressing effect triggered by renewables, i.e., the so-called merit-order effect.

22

The performance of the wind industry has been more successful than that of solar PV (as measured by e.g. patent records). The German solar industry has faced strong competition from China in the production of modules but still remains as the leader in solar PV manufacturing equipment and inverters. See Rutten (2014) and IISD (2014) for a discussion of the impact of environmental and energy policies and industrial policy in Germany.


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2. European climate and energy policy has bolstered national policies, but more progress is needed in certain areas, including carbon pricing and market integration. The energy and climate policies of all three countries - Germany, the UK, and France, - have been increasingly embedded in European policy in this area, at least for the 2020 horizon. The 20-20-20 objectives included in the 2008 European energy and climate package have played a key role as they urged countries to put in place or to reinforce policies capable of achieving the legally binding targets for greenhouse gas emissions reductions, renewables and energy efficiency. In some cases, European climate and energy policies have induced countries to have more ambitious objectives. In others, the integration of pre-existing national and European targets has contributed to defining a more consistent set of targets and policies. The monitoring of the interim targets is also contributing to that end. However, there are some areas where European policy has lagged behind. In particular, the failure of the European Union Emissions Trading System (EU ETS) to deliver a robust carbon price signal has made it more difficult for countries to comply with their decarbonisation commitments. Without disregarding the difficulties, the EU has also failed in promoting a more integrated market, which would have allowed for smoother integration of renewables in the power sector. Arguably, recent initiatives (e.g. the Juncker Investment Plan and the Energy Union package) will help to overcome this, at least partially. The approval of Capacity Allocation and Congestion Management Guidelines should be the basis for a more integrated energy market in Europe.23 Other European policies beyond climate policies - understood in a narrow sense - have also had major impacts on the low-carbon transition. Particularly important in the German and French cases, the implementation of the EU energy packages led to the unbundling of the transmission and distribution networks. This has proved to be a necessary condition for the successful rollout of renewables. As the German case illustrates, network operators had been very critical of the roll-out of wind energy in the early stage. It was only after vertical unbundling that transmission system operators adopted a neutral role towards the deployment of the full range of generation options. Competition policy also has a deep impact on climate and energy policies through State Aid control. In particular, in light of State Aid legislation, the EC has assessed (i) the exemptions given to energyintensive consumers - notably, in Germany and France; (ii) the contract negotiated between the UK government and the French company EDF for the construction of a new nuclear reactor; and it is in the process of evaluating (iii) past renewables policies in several member states. The ex-post evaluation of renewables policies has added regulatory uncertainty among investors. Furthermore, the new 2014 guidelines for state aid on environmental protection and energy narrow down the range of regulatory options for renewable rollout available to the member states. In particular, they 23

The “Regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion management” was published in the Official Journal of the EU on 25 July 2015.


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limit remuneration schemes to a premium that is added to the market price and make renewable installations responsible for balancing their power. These measures will increase the risk faced by investors, while providing limited benefits. 3. The Energy Transition has put extra pressure on electricity bills. This reflects the increase in the costs due to the low carbon policies, but also an unbalanced burden share of the costs among the various consumer groups. In turn, concerns over the increase in energy costs have led governments to water-down some climate policies. Electricity prices for households and businesses have been on the rise. Even though there are several confounding factors, it is beyond dispute that climate policies have contributed to this trend. Indeed, the Energy Transition requires important investments in low carbon technologies and infrastructure, and these add pressure to increase energy bills. With the economic crisis in the background, a large fraction of consumers are finding it increasingly difficult to pay their electricity bills, making the ‘energy poverty’ problem even worse.24 Despite the current price increases, energy costs are expected to go down in the medium-term. A new report from the UK Committee on Climate Change (CCC) has assessed the impact of the UK's low carbon policies on consumer energy bills. Its conclusion is that households would pay more to decarbonise the UK's energy sector in the coming decades, but that energy bills would rise significantly more if the UK failed to implement climate policies.25 Nevertheless, households and firms care about today's prices, and thus they fail to internalise the prospect of future cost reductions. As they become less willing to pay for the current costs of the energy transition, there is a real danger that these policies will be watered-down. Concerns over affordability not only result from the actual costs of the low-carbon transition, but also from the way certain policies have been implemented. In some cases, climate policies have given rise to windfall profits for firms that have made electricity unduly expensive for consumers. In others, some privileged consumers have obtained exemptions to mitigate the electricity price increases at the expense of the non-privileged ones, who have had to bear a larger share of the costs. An example illustrates the first of these issues. Carbon pricing is a necessary condition for efficiency; particularly, as it provides incentives for investors to expand low-carbon capacities. 24

In 2012, energy poverty affected more than 54 million people in Europe, i.e., nearly 11% of the EU's population is in a situation where their households are not able to adequately heat their homes at an affordable cost. This problem affects all three countries under study, and it is particularly acute in the UK. See report commissioned by the EC, Insight_E (2015). 25 For instance, the Committee concludes that an average household on a dual fuel tariff could be paying about £130 more to support decarbonisation in 2030 than today. The additional cost could be more than offset by the money households save by using less energy as a consequence of the policies.


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However, carbon prices are almost fully passed-through to wholesale electricity prices (Fabra and Reguant, 2014; Sijm et al., 2006), leading to increased revenues for the new assets but also for the assets already in existence. Whereas the extra revenues might be needed to incentivise new investors, such revenues are not needed for the existing plants precisely because they already exist. Accordingly, carbon pricing creates windfall profits for the existing low-carbon plants that are ultimately paid for by consumers. These rents are making the energy transition unduly expensive for consumers. And yet, with only a few exceptions, regulators have done nothing to avoid it.26 Free permit allocation is also a source of windfall profits for the pollutants (Fabra and Reguant, 2014; Sijm et al., 2006),27 as the pass-through of carbon prices to electricity prices already compensates them for the extra cost. Regulators have already taken care of these windfall profits earned by pollutants by mandating the use of permit auctions. The revenues obtained through these auctions should be employed to finance the costs of the Energy Transition. However, the windfalls for the non-pollutants remain simply because they have to buy no permits. These have implied a wealth transfer from consumers to operators without delivering environmental benefits.28 Another example illustrates the second issue. In Germany, energy intensive customers have received exemptions for the renewable energy surcharge, which has in turn led to a rapid increase in the surcharges paid by households and small businesses: in 2014, the surcharge paid by nonprivileged consumers was more than 100 times the surcharge paid by privileged consumers (5.28 c/KWh versus 0.05 c/KWh). This asymmetry is even more noticeable if one takes into account the price-depressing effect of renewables. Indeed, wind and solar PV production in Germany have reduced spot market prices by 6€/MWh in 2010 and by 10€/MWh in 2012, with an estimated reduction of 14-16€/MWh by 2016

26

Following the recommendations of the Spanish energy regulator, the government taxed the windfall profits created by the pass-through of carbon prices to electricity prices (from 2006 to 2009, these amounted to approximately 2.800M€). In October 2013, the European Union’s Court of Justice ruled that the claw-back did not violate European Law. The regulator’s proposal can be found here: http://www.cne.es/cne/doc/publicaciones/cne118_06.pdf and the ECJ’s decision can be found here http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:62011CJ0566. 27 For instance, Sijm et al. 2016 estimate that at a CO2 price of 20€/t, ETS-induced windfall profits in the power sector of the Netherlands summed up to €300-600 mln per year, i.e., about €3-5 per MWh. 28 It is important to note that the impact on market prices of increasing input prices is of very different nature as the effect of new regulations. When investors take investment decisions they face, for better or for worse, uncertainty over input costs and their impact on market prices. However, they do not (and should not) face regulatory uncertainty, for better or for worse, e.g. if a nuclear plant is shut down prematurely because of a regulatory decision, investors should be compensated for the windfall loss. For similar reasons, windfalls that arise because of regulatory decisions should not accrue to firms, as if that was the case, consumers would face a windfall loss. Accordingly, the clawback should not apply to installations that have come on line after 2005 when the emissions regulation was first implemented.


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(Cludius et al., 2014). Thus, while energy intensive consumers have benefitted relatively more from reduced power prices, they have contributed disproportionally less to financing the costs of the renewables roll out. 29 This asymmetry will widen in the future as the increased weight in renewables further reduces spot market prices, thus enlarging the size of the surcharge to be paid by non-privileged consumers. Paradoxically, these measures might have been necessary to avoid opposition to the Energy Transition by energy-intensive consumers. However, by imposing a disproportionally large share of the costs on households and small businesses, it has also given rise to tensions. Distributional issues have also been contentious in the UK, where cost increases have fallen more heavily on poorer households. This has been partly offset by various programmes (such as Cold Weather and Winter Fuel Payments, and energy efficiency measures). However, these have not always been well-targeted and as a result there has been a transfer from those who do not benefit (many of whom are poor) to those who do benefit (some of whom are rich). Affordability is certainly a necessary condition to obtain social support for the policy changes. However, consumers’ support also depends on other factors. The German case offers a paramount example as, despite the price increases, the Energiewende has received broad public support. While this can be partly explained by the intrinsic values of German society, the involvement of new players in the Energy Transition (including households, farmers and small and medium sized firms who have invested in renewable technologies) has certainly played a major role in securing broad support for climate policies. Over time, this broad economic participation has stabilised the policy arena for the Energy Transition and strengthened the robustness of the transition pathway. 4. The ETS has delivered a weak carbon price signal. Countries have had to strengthen the carbon signal by adding additional mechanisms. With the creation in 2005 of the European Union’s Emissions Trading System (EU ETS), Europe showed that it is possible to build up a carbon market that delivers a region-wide carbon price. However, with the economic crisis and the rapid expansion of renewables in the background, the EU ETS has delivered prices that are too low and too volatile to affect investment and production decisions in a meaningful way. Indeed, for the carbon price to have a substantial impact in the power sector, it has to stay above €30-40 per Ton. These figures are well above the ETS prices, which have remained under €10 on average, sometimes as low as €3. It is thus not surprising that, over this period, Europe has failed to reduce coal-fired generation. In fact, from 2011 to 2012, the weight of coal-fired generation has grown by 13%, gas-fired generation has dropped by 23%, and nuclear generation has declined by 2.8% (mainly due to the German nuclear phase-out decision). As 29

Cludius et al. (2014) estimate a zero net effect for privileged consumers, i.e., the renewables roll out policy has not increased nor decreased the energy cost for the privileged consumers; in other words, the nonprivileged consumers have fully paid for the cost of the policy.


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a consequence, the carbon intensity in the power sector has increased. This suggests that the EU ETS has not been successful in minimising the costs of emissions reductions, failing to induce the exit of high-carbon technologies. Given the weaknesses of the ETS, the UK introduced in 2011 a Carbon Price Floor to ensure that carbon prices moved on a trajectory that would make low carbon investments profitable. The Carbon Price Floor would start at £16/tonne in 2013, rising to £30/tonne in 2020, and projected to rise to £70/tonne by 2030 (all at 2009 prices). However, because of fears that it might adversely impact British competitiveness, political pressure quickly led the government to freeze the price floor at its early low level. Also, Germany has tried to pass a Climate Levy by which the most polluting installations would effectively face a marginal carbon price twice as high as the ETS price. However, the plan has failed due to political opposition. These two examples show that adopting carbon policies at the member state level can be politically challenging while being more distortive than a common policy at the EU level. Despite its low prices, the ETS has provided some incentives for investment in R&D. Indeed, a study covering the first five years of operation of the EU ETS, comprising data on over 30 million firms across 23 countries, shows that carbon pricing had a significant impact on technological change. In particular, those firms subject to the emissions regulation increased low-carbon innovation by as much as 10%, while not crowding out patenting for other technologies. As a consequence, the ETS led to a nearly-1% increase in European low-carbon patenting as compared to a counterfactual scenario (Calel and Dechezleprêtre, 2015). Interestingly, permit allocation mechanisms have also had a significant effect on firms’ incentives to innovate. Indeed, those sectors that are just below the thresholds required for free allocation are more innovative than those just above those thresholds (Martin et al., 2013). Despite the overall importance of carbon pricing for innovation incentives, evidence from the power sector suggests that, given the low and volatile carbon prices, policies towards renewables, namely ROCs and FiTs, have been stronger drivers of innovation.30 5. Renewable energies have played a prominent role in the Energy Transition. Their costs have gone down beyond expectations. Renewables are playing a prominent role in the transition towards a low carbon economy. In Germany, renewables currently represent almost 30% of total electricity generation, and it is estimated that renewables will account for more than 50% by 2030. The current weight of renewables in the power sectors in the UK and France is much lower than in Germany. However, the weight of renewables is expected to increase significantly in the next decade as they both seek

30

A survey of this evidence can be found at Martin et al. (2014).


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to comply with their EU commitments for 2020.31 Under all scenarios, renewables will become the main source of electricity generation in Europe by 2030, reaching up to 80-90% by 2050. Renewables have also played a key role in addressing the energy trilemma. As reported by the European Commission, the EU's 2020 renewables target has resulted in around 388 Mt of avoided CO2 emissions in 2013, leading to a reduction in the EU's demand for fossil fuels of 116 Mt. Further, this has boosted the EU's security of supply by reducing fossil-fuel import dependency. An on-going study by the European Commission estimates that €30 billion were saved in 2010 by not importing additional non-renewable fuel. This figure is to be compared with the €18.6 billion that were spent in 2010 on renewable support in the EU. While the environmental benefits of renewable energy are clear, the role that renewable energy can play also depends on its cost effectiveness. Evidence shows that the more mature renewable technologies, such as on-shore wind and solar PV, are becoming increasingly competitive with respect to the fossil fuel alternatives. Indeed, during the last 20 years, these two technologies have achieved major cost reductions: the costs of generating electricity from wind have fallen 50% since 1990; similarly, the costs of solar PV have fallen by 80-90% since then. Forecasts of future costs indicate that the costs of these two technologies will keep on approaching the costs of the conventional energy sources (IRENA, 2014; IEA, 2015).32 The costs of the less mature renewable technologies (off-shore wind; wave power; solar thermal; geothermal energy or biomass) are still much higher. However, their future costs are also expected to fall as they benefit from R&D and learning externalities. The following quote from a 2014 Ernst & Young report is illustrative of this trend: ‘Investment cost estimates made in 2011 by the European Commission and the European Climate Foundation for renewable energy generation equipment, grids and storage, were overestimated…Several renewable energy solutions have accelerated their cost reduction trajectory beyond expectations, thus making the renewable energy pathway more attractive for Europe. This cost reduction has been so significant that the cost level for [photovoltaic] that was expected for 2050 in the ECF Roadmap 2050 has already been reached.’ The current remuneration of the more mature renewable energies is already capturing these cost reductions.33 The recent capacity auction that was held in February 2015 in the UK cleared at prices 31

See the latest progress report published by the European Commission's on the achievement of the 2013/2014 interim renewable energy targets. Available at http://ec.europa.eu/energy/en/topics/renewableenergy/progress-reports 32 See also the report, 'In Sight: Unsubsidised UK Solar', which predicts that all three sectors of the UK solar market (ground-mount, commercial and domestic) will be able to compete without subsidy with traditional forms of energy within the next 10 years. 33 It is important to note that the higher rates paid to the first round of renewable investments do not imply that those investments were inefficient or that they are now been overpaid. To the contrary, it would not


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close to £70/MWh for both onshore wind and solar PV, with a 15 year guarantee.34 In Germany, depending on plant size and location, onshore wind farms are remunerated at 70-100 €/MWh and solar PV plants are paid at 120-180€/MWh, with a 20 year guaranteed remuneration. In France, the FiTs for the last quarter of 2014 are at 68€/MWh for ground solar PV with a 20 year guarantee. For wind, the FiT is at 82€/MWh for the first 10 years and between 28€/MWh and 82€/MWh for the remaining 5 years. 6. The success of the early roll out of renewables rested on technology-specific Feed-in-Tariffs. However, the FiT system broadly failed to adjust the tariffs in line with the cost reductions, and in controlling total investment. The success of the early roll out of renewables in Germany rested on technology-specific Feed-inTariffs (FiTs). The technology-specific focus has allowed some technologies, notably solar, to achieve cost reductions that would have been difficult to achieve under a fully technology neutral approach. Indeed, solar PV has experienced one of the fastest reductions in investment costs. Their costs are now close to the costs of wind even though in the early 2000s the costs of wind were much lower than those of solar PV.35 The German approach also offered contracts of differing degrees of generosity to on-shore wind farms based on measured output in the first three years of operation. In contrast to the ROC system used in the UK (that paid the same price regardless of location), this reduced the rents in more profitable locations, thus reducing the cost to consumers of supporting renewables. The FiT system used in Germany - and subsequently in France - contributed to creating regulatory certainty, as payments per MWh were fixed for sufficiently long periods (typically, 15 or 20 years). Furthermore, other features of the FiTs also contributed to their effectiveness: their simplicity, as they paid investors for metered output, and the fact that they do not make investors responsible for predicting and selling their output. This further contributed to encouraging participation of small investors (farmers, home-owners and small or medium-sized firms), which in turn led to a fragmentation of the market structure and allowed for broad societal support of the renewable rollout. All this contributed to a rapid deployment of new installations. The early rollout triggered cost reductions, which in turn induced further deployment. However, cost reductions were faster than expected and the FiT system failed to adjust the tariffs for the new installations accordingly. Thus, have been feasible to achieve the current lower rates without the learning externalities triggered by the first round of investments. 34 Two solar projects were allocated at £50/MWh. However, they have been withdrawn a few days after the auction was held. 35 This is confirmed by the seminal paper by Johnstone et al. (2010), which emphasizes that FiTs have played a major role in promoting innovation the early phases of the renewable energy rollout. Their analysis is conducted using patent data on a panel of 25 countries over the period 1978–2003.


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some countries witnessed a boom in installations exceeding the initial objectives, which added financial pressure to the cost of the support schemes. To mitigate this, some countries – Germany and France, among them –introduced mechanisms to facilitate the adjustments of FiTs over time. In particular, they made tariffs dependent on the excess demand for FiTs in previous rounds as compared to the objectives. While this scheme has allowed for some degree of tariff adjustment, there are still some drawbacks: there are lags from one round to another, and it is not easy to choose the correct tariff digression without reliable information on the costs of deployment. Costs change quickly, and only investors know the actual investment costs. There is an alternative way to allow tariffs to converge to the costs of renewables, namely, through the use of auctions. The experience with the use of auctions for renewables in the UK is very positive. The first auctions that were used in the UK back in the 1990s contributed to significant cost reductions. Similarly, the auction that was held last year for Contracts for Differences for renewables resulted in strike prices well below expectations. However, in both cases, experience shows that more emphasis should be put into the design of penalties for non-delivery. 7. Market arrangements have failed to promote efficient investments in generation capacity. Countries have tried to address this issue in an uncoordinated fashion. In most member states, overinvestment in gas-fired plants followed by the rollout of renewables and the stagnation of demand, have given rise to an excess of generation capacity.36 Indeed, several fossil fuel plants are operating at low utilisation rates while receiving low and volatile wholesale electricity markets. The UK is probably an exception in Europe as it is the only country in which the reliability index is tight. A distinguishing feature of the UK market was its reliance on a (truly) energy only market, which is probably at the heart of the investment problem. Indeed, the reserve capacity margin in the UK has been steadily going down since 2012, when it first fell below 10%.37 In any event, both pieces of evidence demonstrate that investment decisions have been inefficient either because there has been too much or too little investment. As a consequence, several member states have adopted capacity mechanisms. The design of capacity mechanisms differs markedly across countries, despite the EC’s attempts to harmonise

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It is not a contradiction to push for more renewables given the current degree of excess capacity. Depending on the state of the technology, the average costs of new investments in renewables might be lower than the marginal costs of existing assets (particularly so, in a scenario of high carbon prices). For instance, with the variable costs of CCGTs at 60€/MWh, a 50€/ton carbon price would drive the electricity market price up to 75-80€/MWh, a figure which is in line with the strike prices agreed in the last renewable capacity tender in the UK. Hence, even if there is over-capacity in some countries, it might still be efficient to keep on investing in low carbon alternatives. 37 France might also face generation adequacy problems in the (relatively) short run, as a consequence of decommissioning of conventional plants that do not meet environmental requirements.


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these rules.38 DG Competition has also been critical of the use of capacity payments, arguing that they often have more to do with compensating generators in difficult financial conditions rather than with guaranteeing security of supply at least cost. Indeed, DG COMP has launched a sector inquiry into capacity mechanisms to assess whether these are compatible with State Aid regulations.39 Experience with the use of these diverse market designs is too brief to derive relevant lessons. However, it seems clear that the use of different regulatory solutions to address a problem that spreads beyond national borders creates inefficiencies, and leads to tensions among neighbouring countries. 8. R&D has played an important role. Both the climate policies as well as the increase in public expenditure have been important drivers of R&D. One of the successes of the Energiewende regards R&D and innovation. Although it is not straightforward to disentangle the causal impacts of climate policies from the effect of other confounding factors, it is widely recognised that the implementation of climate policies in Germany triggered major technological breakthroughs across several fields (basic technologies, system and sector integration, demand flexibility, storage, smart grids, etc.) as well as cost reductions (particularly so in onshore wind generation, solar photovoltaics and parts of micro CHP).40 The research sector has also witnessed the emergence of industrial start-ups as major industrial players, who have in turn contributed to fragmenting the market structure. Public expenditure on energy related R&D has been very relevant in Germany, where public funding for research on energy efficiency, renewable energies, and energy infrastructure (including storage) rose from €400m in 2006 to more than €800m in 2013. Major R&D efforts have also been undertaken by the industry as a consequence of the incentives provided for the demonstration and early roll-out of renewables. Last, but not least, the public and political support for the Energiewende has provided a further stimulus to energy research by creating a supportive social environment. The UK provides another interesting example on how R&D in low carbon technologies can be promoted, particularly so when it is undertaken by regulated firms subject to price-cap regulation, as has traditionally been the case for energy network operators. If the parameters of the RPI-x regulation are too stringent, e.g. if the price control periods are too short, firms’ incentives to innovate are weakened as cost reductions achieved through R&D are taken back shortly after firms achieve them. To mitigate this, the price control periods have been extended from five to eight 38

See the Commission’s communication, Delivering the internal electricity market and making the most of public intervention – C(2013). 39 http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html. 40 See Johnstone et al. (2010) for evidence on the impact of climate policies patent activity.


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years, allowing utilities to keep innovation gains for a longer period. Furthermore, the energy regulator Ofgem has created a Low Carbon Network Fund (LCNF) with a £500 million budget to award in annual competitions to projects capable of reducing the carbon intensity of the networks and/or facilitating the connection of low-carbon technologies to the grid. 9. Efforts in promoting energy efficient have been weak. There is mixed evidence concerning the potential of some of these policies to reduce energy consumption. Investments in energy efficiency can potentially address all three objectives of the energy trilemma: energy supplies have to be sustainable, affordable and secure. Indeed, energy savings contribute to security of supply by reducing import dependency: estimates by the European Commission41show that a 1% increase in energy savings could diminish gas imports by 2.6%. Energy efficiency also addresses the affordability objective as it allows consumers to save money by reducing the amount of energy they use, even though they often require costly investments. Last, but not least, energy savings help to alleviate environmental concerns through their contribution to cutting greenhouse gas emissions. Europe has set ambitious objectives in terms of energy efficiency, and some countries have put in place policies to help achieve those targets. The overall EU-wide objective is to improve energy efficiency by 27% by 2030 with respect to 1990 levels. Germany has set the goal of reducing primary energy consumption 20% by 2020, and 50% by 2050, as compared with 2008. France has also an ambitious energy consumption objective as it has committed to reducing it by 50% with respect to 2012 by 2050. Despite the important achievement towards decarbonisation and renewable energy rollout, the area where Europe lags behind is energy efficiency. The evidence on the potential for energy efficiency investments to deliver significant cost and energy savings is mixed. First, there is the socalled ‘rebound effect’: after efficiency upgrades, consumers adjust their behaviours and consume more energy. This is in turn triggered by the combination of two effects: a price effect –efficiency upgrades reduce the per unit cost of energy-intensive goods - and an income effect –energy savings free wealth that can be used to buy other goods that also consume energy. Even though the rebound is likely to significantly reduce the net savings from energy efficiency improvements, the existing evidence points at a low likelihood of backfire. However, the International Energy Agency (IEA, 2014) has recently concluded that the rebound effect could reach as high as 60%.42 This does not mean that efforts to improve energy efficiency should be abandoned. Rather, it means that

41

See the EC’s Communication on Energy Efficiency and its contribution to energy security and the 2030 Framework for climate and energy policy, July 2014. 42 However, there is mixed evidence about the magnitude of the rebound effect. Indeed, it is widely acknowledged that estimating the rebound effect is extraordinarily difficult. See Gillingham et al. 2015.


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more efforts should be devoted to mitigate43 and/or compensate for the rebound effect (either through further investments in low carbon assets or through measures to promote demand response and savings). Second, there is the so-called energy-efficiency gap, i.e., consumers and firms seem to fail in undertaking investments in energy efficiency that would increase utility or profits.44 There are several potential reasons for this gap, including (i) market failures (innovation externalities, information issues, capital market imperfections, etc.), (ii) behavioural biases and (iii) modelling flaws. For instance, one of the most important factors hindering investments in energy efficient technologies is limited access to capital. This issue is particularly critical given the high upfront costs and the relatively long payback periods of these investments. At the residential level, there is scope for energy efficiency improvements in the form of small and fragmented investments. However, it is also at the residential level where market failures tend to be more acute, and thus, where policy could have stronger impacts. Having said this, one cannot disregard that, given the current state of the technology, one potential cause for the energy-efficiency gap is a miscalculation: the costs of efficiency upgrades have been underestimated and/or the potential energy savings have been overestimated. According to this, consumers would not be investing in energy efficiency simply because it does not pay back. A recently conducted randomised controlled trial of more than 30,000 households shows that residential energy efficiency investments may not deliver the expected gains (Fowlie et al., 2015). Participating low-income households were freely provided with about $5,000 worth of energy efficiency upgrades. These allowed households to reduce their energy consumption by about 10 to 20% each month, translating into $2,400 in savings over the lifetime of the upgrades. These savings are modest, to the extent that they only cover half of the upgrade costs, and less than half of expected energy savings. While more evidence is still needed, these results show that the net returns on energy efficiency investments might be lower than expected. More research in this area is needed to disentangle whether a true energy efficiency gap exists, and if so, how it can be efficiently addressed. Again, rather than abandoning the efforts to promote investments in energy efficiency, it is paramount to understand why some measures deliver satisfactory results while others don’t. 43

For instance, a report by the German Energy Agency (DENA) indicates that after an empirical study on deep retrofitted buildings, the rebound effect reached only 6% on average. This was mainly due to ongoing technical support to improve consumers’ awareness. Indeed, consumer awareness through e.g. eco-design and labelling can play a major role in reducing emissions. It has been estimated that the Ecodesign Directive will save 400 million tonnes of carbon dioxide emissions within the EU, comparable to the Emissions Trading System’s (ETS) anticipated contribution to carbon dioxide reductions in 2020. See http://ec.europa.eu/enterprise/magazine/articles/sustainable-industry-innovation/article_11045_en.htm 44 The seminal paper on this topic is Jaffe and Stavins (1992). For recent evidence, see Allcott and Greenstone (2012).


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1.5 Policy recommendations: towards a low carbon power sector In this section we derive policy recommendations aimed at facilitating the Energy Transition at least cost. Some of them are directly linked to the experience in Germany, the UK and France; others derive more broadly from the economics of energy and climate change: 1. National governments should commit to supporting the Energy Transition without further delay. 2. More emphasis should be put into strengthening cooperation between countries. In this sense, market integration and policy convergence across countries should be promoted. 3. The Energy Transition has to be affordable. Distributional issues (between consumer groups, as well as between firms and consumers) should have a central role when designing and implementing policy. 4. Carbon pricing should be strengthened as it is crucial for the Energy Transition. However, it might not be enough, particularly so in the medium to long run. 5. Renewables must play a prominent role, for environmental as well as for economic reasons. 6. For large renewable installations, there should be a shift towards the use of auctions for long-term contracts. For small installations, the FiT system should be retained. Renewables should not be made responsible for balancing and marketing their electricity. 7. Auctions for long-term contracts should be used to promote investments in back up capacity and plant flexibility. 8. Research and development must be promoted. The impact of regulatory policies on market structure and on the incentives to innovate should be carefully assessed when designing policy. 9. Regulatory stability is crucial for investors' confidence. This is not in contradiction with the need to have rules that evolve during the transition period as long as the course of changes is clearly set and announced in advance. Below, we provide a more detailed discussion of the recommendations outlined above. 1. National governments should commit to supporting the Energy Transition without further delay It is urgent to put in place policies aimed at drastically cutting greenhouse gas emissions. Otherwise, atmospheric concentrations of carbon dioxide will keep on rising above 400 ppm, thus leading to an increase in global warming above and beyond 2°C. The urgent need to implement decarbonisation policies applies to all sectors involved in the Energy Transition, but particularly so to the power sector. Since power plants are long-lived assets, any investment today that does not contribute towards decarbonisation can lock us out of a low-carbon future. The effects would spread across other sectors, as delays in the decarbonisation of the


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power sector would further delay the decarbonisation of the rest of the economy. Decarbonisation of the whole economy would simply be unfeasible without a deep decarbonisation of the power sector. 2. More emphasis should be put into strengthening cooperation between countries. In this sense, market integration and policy convergence across countries should be promoted. The fight against climate change creates a global public good. In the long run, all countries benefit from the reduction in global warming. However, in the short run, there are powerful incentives to leave the burden of reducing greenhouse gas emissions to others. If all countries do the same, climate change action will not take place. Using Game Theory jargon, the fight against climate change leaves countries facing a prisoner’s dilemma: they all want to free-ride on the efforts of others, but if they all do so, efforts will not be enough. As is well known, the efficient solution to this dilemma can only be achieved through cooperation. Simply, the Energy Transition cannot be achieved by countries operating on their own. In Europe, the completion of the internal energy market should be seen as a key instrument to achieve closer coordination among Member States. Indeed, the recently published Energy Union package puts the internal market at the core of its climate and energy policies. The strengthening of the internal energy market through increased interconnection contributes to the environmental agenda. A more closely-linked electricity network facilitates the integration of renewables into the electricity system by reducing the amount of back-up capacity necessary to compensate for their intermittency. In particular, market integration would allow for a pooling of dispatchable resources across European countries. Since electricity demand net of the production of intermittent resources is not perfectly correlated across European countries, the overall net load is flatter at the EU level than at the level of the individual member states. This has two important implications. First, the peak of net demand in an integrated system is lower than the sum of the peaks at the individual member states. Thus, market integration would reduce the cost of keeping back-up capacity to meet peak load whenever there is not enough wind or sun to meet total demand. Similarly, the minimum load in an integrated system is higher than the sum of the minimum loads at the individual member states. Since overproduction occurs when renewable energy production peaks at times of low demand, market integration also enables a better use of renewable resources. Market integration will become increasingly important as the weight of renewables increases as these two issues – the need to resort to back-up capacity and the potential for over-production – will become more relevant. The need to harmonise market rules as a condition for market integration should not be overemphasised. While some degree of harmonisation is important, it should not come at the cost of imposing solutions which might be suitable for some but not for all countries. Participation and shared values might be more important than full harmonisation, and these cannot be achieved if


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certain regulatory solutions are imposed on the countries. Furthermore, countries are at different stages of the decarbonisation process, which implies that policy convergence with some degree of flexibility, rather than full harmonisation, might be preferable. Despite all of the above, it is essential to acknowledge that market integration might imply some rebalancing across Europe, with consumers in low energy price countries facing higher prices from interconnections which would result in national producers exporting electricity to high price countries. To obtain support for market integration from all Member States, regulatory measures should be put in place to mitigate the negative impacts that market integration might have on some consumers. 3. The Energy Transition has to be affordable. Distributional issues (between consumer groups, as well as between firms and consumers) should have a central role when designing and implementing policy. There is a clear tension between sustainability and affordability objectives. If the path towards a low carbon economy is not affordable, it will simply not get the necessary public and political support that is needed to address such a fundamental transformation of the energy system. In order to obtain the necessary public support, governments and regulators should stress that today’s investments will pay back as they will allow for cheaper energy supplies in the medium to long term. Indeed, countries stand to gain more than they would lose in economic terms from almost all of the actions needed to tackle climate change (Green, 2015). It is paramount not to make the energy transition unduly expensive for consumers. This is a matter of equity, but it is also a matter of efficiency: if the costs for consumers are too high, they will not support the energy transition policies. Therefore, these policies will not be implemented even if they are efficient overall. In turn, this suggests three important conclusions: •

Regulators should avoid a misallocation of risks that creates inefficient costs;

•

Regulators should avoid rents being created through this long process; and

•

Regulators should avoid a scenario where certain consumers bear an unfair share of the costs.

The first two issues point to the importance of devising market arrangements that (i) minimise total costs through an efficient risk allocation, (ii) avoid overpaying certain generation technologies, and (iii) reduce the scope for market power. We turn to these issues at the end of this section. The third issue suggests that the extent of the exemptions given to privileged consumers should be reassessed.


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4. Carbon pricing should be strengthened as it is crucial for the Energy Transition. However, it might not be enough, particularly so in the medium to long run. Without carbon pricing, the negative externality created by carbon emissions remains unpriced. Putting a price on carbon is thus a necessary condition for efficiency as it encourages polluters to take all available steps to reduce emissions that cost less than that carbon price. In this way, emissions reductions are achieved in a least cost way. The experience so far does not invalidate the importance of carbon pricing, but rather suggests that more should be done in order to strengthen the carbon price signal. For this, it is paramount to remove the excess of allowances from the market, to tighten the cap, and to widen the range of sectors subject to the emissions regulation. The creation of a ‘market stability reserve’ should allow for more stable carbon prices, as any surplus or deficit of allowances above an upper end or below a lower end will be placed in the reserve or released from it, respectively. However, the efficacy of this reform is yet to be corroborated in practice. In particular, the ETS will have to have enough flexibility to absorb the likely excess of allowances as ambitious levels of renewables and energy efficiency will keep on reducing the overall demand for permits. In any event, it has to be acknowledged that the efficacy of carbon pricing to induce changes in production and investment patterns in the power sector will be undermined as we move closer to the objective of an almost carbon-free power sector. Indeed, under a high penetration of renewables, the number of hours during which fossil plants will set the market price will go down, and thus the carbon price will no longer be passed-through to the electricity price. Under this scenario, carbon prices will not be enough to generate the flow of revenues that investments in low-carbon assets require. Given that low-carbon assets are long-lived, investors today might already be internalising this future trend, to the detriment of today’s investments. 5. Renewables must play a prominent role in the Energy Transition, for environmental as well as for economic reasons. The Energy Transition cannot be accomplished without a prominent role for renewables. First and foremost, renewable energies have zero emissions and hence are a key ingredient for decarbonisation. And second, they contribute to making the Energy Transition affordable. As argued above, renewables have experienced very significant cost reductions, which are already being passed on to consumers through lower tariffs for the new investments. Forecasts of future costs indicate that even the more mature renewable technologies will keep on reducing their costs further, albeit at a slower pace. Nevertheless, renewables are not the only low carbon option available. Nuclear and Carbon Capture and Storage (CCS) also provide zero-carbon alternatives. How do renewables compare against these other options? The new CfDs in the UK power sector provide meaningful figures to


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shed light on this question. The new nuclear reactor that will be built in the UK (Hinkley Point C) will receive a Contract for Differences with a £92.50/MWh strike price during 20 years.45 This is to be compared with the £70/MWh strike prices that on average have been allocated to new wind and solar farms in the last auction in the UK. However, for the cost comparison to be meaningful, one also has to add the costs of back-up capacity needed to guarantee security of supply in a renewable-based power sector. The German think-tank Agora has conducted this exercise by comparing the current FiTs in Germany with the agreed strike price for new nuclear in the UK and the current cost estimates for CCS, neglecting future technology cost reductions in any of these four technologies. They conclude that the generation costs of new wind and solar is 50% lower than those of new nuclear and CCS, and 20% lower when the renewable option is supplemented with back up capacity of natural gas-fired plants (Agora, 2014). Having said this, the nuclear industry is working on improvements that target cost reductions in the construction of the new generation nuclear reactors, like the one to be built in Hinckley Point. Similarly, CCS is at the beginning of its learning curve. Therefore, more evidence will be needed to assess the economic performance of these alternatives in the future, as the outcomes of the learning curves are still uncertain.46 However, while the reductions in the cost of renewables are generally clear, major technological breakthroughs are still needed to achieve costs reductions in the cases of nuclear and CCS before they can be considered as possible commercially viable options. 6. For large renewable installations, there should be a shift towards the use of auctions of longterm contracts. For small installations, the FiT system should be retained. Renewables should not be made responsible for balancing and marketing their electricity. Given the key role that renewables play in the Energy Transition, what should be the policy towards their deployment? Long-term Contracts for Differences: Electricity spot markets expose renewables to excessive risks. Renewables involve high upfront capital costs, and low and constant variable costs which are uncorrelated with the wholesale market prices (the latter depend on the prices of fossil fuels and carbon prices). Hence, the profit margins of non-fossil generation are too low and volatile, thus leading to inefficient risk premia. Furthermore, investors do not take investment decisions based on the current profitability of 45

Or £89.50/MWh if the planned new nuclear power plant at Sizewell goes ahead. The existing literature acknowledges the difficulties in estimating learning curves, revealing wide ranges in the learning rates of the various technologies. Most of the results reveal larger learning rates are for renewable energy sources (especially for wind and PV), smaller learning rates for fossil fuel plants, and mostly negative rates for existing nuclear plants. See Rubin et al. (2014) for a survey of this literature. 46


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existing assets, but rather about the derivative, i.e., about the effect that new investments will have on the profitability of the old and the new assets. Hence, the price depressing effect of renewables implies an additional barrier to the deployment of renewables when their remuneration is based on spot prices. The higher the weight of renewables in the energy mix, the more important this effect will be, given that renewables will deliver the full load in an increasing number of hours over the year. In this scenario, long-term Contracts for Differences (CfD) reduce the risk of investments by guaranteeing investors a fixed price, regardless of movements in spot market prices. In turn, this lowers the cost of capital, ultimately benefitting consumers. Tenders for renewables for large installations: The challenge with CfDs is to determine the correct strike price. Competition through auctions provides virtually the only means by which strike prices can converge to the investors’ actual costs. Across all EU member states, we will see a shift towards the use of tenders for renewables, which the recent state aid guidelines have made compulsory from 2017 onwards. While the use of auctions in the UK offers only a brief experience, their approach seems promising in the light of the cost reductions they have achieved. Unlike the previous failures when setting FiTs, the use of auctions will push down the prices paid by consumers for renewables. Furthermore, they will allow for a tighter control of the amounts to be invested, avoiding excessive investments. An important issue regarding the design of auctions is whether they can efficiently incorporate locational signals. Concentrating renewable resources in some locations might lead to excess supply to a locally constrained distribution network in sunny or windy hours. As a result, such investments are worth less than investments in unconstrained zones. Hence, renewables should be encouraged to locate where they are most valuable, i.e., where the correlations with other existing renewable installations is lower (i.e. farther away and/or on different networks). Uniform prices over time and space don’t induce correct locational signals. Locational grid charges might help towards that end, but they lack credibility as they can be reset during the lifetime of the investment. For this reasons, it is preferable that contracts incorporate such location signals. One way to do it is to adjust the bids of the competing investments according to the costs imposed on the system as reflected by their potential location. Regulators and competition policy authorities have important roles to play in (i) designing the auction rules and the contracts to be auctioned-off (which duration, which technologies, which requirements) and in (ii) making sure bidders behave competitively. Contentious issues in the design of auctions are the penalties for non-delivery so as to avoid winners walking away from the contract if, ex-post, they find the project unprofitable. The EU should study the possibility of conducting EU-wide auctions in order to achieve more efficient location decisions and induce more competitive pressure, while creating sufficiently large demand-pull to drive down production costs.


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Feed-in-Tariffs for small installations: As we have learnt from the German experience, the participation of small investors in the renewables roll out contributes to fragmenting the market structure and allows for broader societal support for the renewable rollout. For these investors, participation in auctions can be cumbersome. Hence, for small installations, standard FiTs should be used.47 Tariffs can be made a function of the prices in the auctions for large installations– with some adjustment due to scale differences - and they can also be adjusted according to excess demand in previous rounds. Regulators should also put in place mechanisms for volume control, so as to avoid excessive investments. Renewables should not be made responsible for marketing and balancing their energy: Costs to consumers could be further reduced if the authorities re-assessed the use of market solutions for the marketing and balancing of renewable energy. It is widely acknowledged that efficiency requires risk to be allocated to less risk-averse agents with the capacity to manage/avoid risk. Different regulatory instruments have different consequences in terms of risk allocation. For instance, under the classic Feed-in-Tariff solution, the investor is paid on metered output at the agreed price, but keeps the production risk as weather conditions are uncertain. Under the current CfDs, there is little price risk, but investors are responsible for balancing the unpredictable wind or solar output. In practice, most independent renewables developers on CfDs shift balancing risk by signing FiTs with aggregators, at a discount of 10-15% of the expected strike price. These premia are eventually paid for by consumers, as they are passed on to the strike prices that are auctioned off. Since there is little investors can do to avoid such risk, it would be more efficient to instruct the System Operator to offer the same risk transfer at a lower cost, as the System Operator is best placed to predict total renewable production and manage system balancing. Hence, the risk allocation embodied in CfDs could substantially raise the support cost of renewables with no clear efficiency benefits. The incentives induced when facing renewable installations with the wholesale market price and balancing risks are unclear, as the production of renewable resources is almost fully exogenous to the investors’ decisions. This is the reflection of a standard Principal-Agent trade-off between incentives and risk. Furthermore, larger companies can manage their whole portfolio and hence they can self-balance better than smaller merchant renewable investors. Thus, making renewables responsible for balancing their energy introduces a barrier of entry for smaller players, which have proved so important in fostering the Energy Transition in Europe. One option that could be explored is 47

If this asymmetric regulation is to be implemented, it is important to avoid strategic behaviour by the investors, who might decide to split large projects into smaller pieces. There are easy ways to avoid this, e.g. through the definition of what constitutes an installation.


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whether it would make sense to face big players with balancing responsibilities but not the smaller ones. However, here again one would face the trade-off between incentives and risk, though in the case of bigger players this trade-off is less acute. Technology-specific focus: A contentious issue is whether all renewable technologies should receive the same strike price (technology-neutral approach) or whether differences in the state of the technology rather suggest the need to treat them differently (technology-specific approach). Several reasons recommend adopting a technology-specific approach, at least in the short to medium run: (i) Under a fully technology neutral approach, investors pick the cheap technology today, but this need not be the most efficient one in the long run. (ii) Putting different technologies in competition at the same auction might give rise to excessive rents to the low cost one. (iii) Given the uncertainties and challenges associated with the individual technologies, developing a portfolio of renewable technologies serves as a hedge. (iv) Some of these technologies serve complimentary roles; e.g. solar production fades down at sunset while the wind blows predominantly at night. This does not mean that a technology-specific approach should always be adopted. Since the learning curve depicts decreasing returns, mature technologies create much weaker learning effects. Furthermore, as their costs converge, the rents that the low cost technologies would obtain under a technology neutral mechanism would diminish. Hence, arguments (i) and (ii) above in favour of a technology-specific support become weaker as technologies approach maturity- even though arguments (iii) and (iv) remain valid. In the long run, the aim is to create a level playing field where all generators can compete on an equal footing to ensure that decarbonisation objectives are achieved at the lowest cost. For this purpose, it is important to have the timing right: ceasing technology-specific support prematurely would endanger the learning externalities, which are at the root of the future cost reductions. Even though the EU supports a technology neutral approach, the EEAG leaves ample ambiguity for regulators to decide whether to employ technology specific policies. This flexibility should be used wisely by the member states. 7. Auctions for long-term contracts should also be used to promote investments in back up capacity and plant flexibility. A large part of the discussion above regarding renewables also applies to the back-up capacity. Theory and practice point to a market failure in the provision of back-up capacity: the public good features of security of supply coupled with the existence of price caps result in a missing money problem, which in turn leads to underinvestment (Joskow, 2006). Furthermore, owners of back up plants face excessive risk given that they operate during a small and uncertain number of hours.


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Just as in the case of renewables, their production can be broadly considered to be exogenous as they have to operate whenever demand exceeds renewable production, both of which are random. Since the market fails, the regulator has to step in to determine the amount of back-up capacity that has to be made available, as well as to put in place mechanisms to make sure that firms have incentives to do so. Just as with renewables, the solution could come through competition for longterm contracts referenced to a liquid spot market. In both cases, there should be a shift from competition in the market to competition for the market as the focus moves from short-term production decisions to long-run investment decisions. Clearly, to the extent that the demand side (e.g. through load management and load curtailment by the industry) can offer similar services to balance the system, it should be allowed to compete for such contracts. If the market is governed by competition for long-term contracts, there would be no need to introduce additional capacity markets. Or rather, competition for long-term contracts is a capacity market in itself (though much simpler than decentralised capacity markets, as the one which is about to be introduced in France). The stream of revenues needed to provide investment incentives would already be embodied in those contracts. The focus on capacity does not mean that energy markets should cease to exist. On the contrary, liquidity of such markets is paramount for productive efficiency. However, the bulk of the revenue stream for investors would be determined at the auctions for long-term contracts. Furthermore, since most generators would be subject to CfDs, their incentives to exercise market power in the energy market will be greatly diminished. Just as in the case of renewables, the regulator might be concerned not only about the amount of back up capacity, but also about its type. Flexibility is increasingly needed to cope with the intermittency of renewable resources,48 and different plants differ in their degrees of flexibility (because they might have different minimum loads and start-up times).49 Hence, this might justify the regulator favouring more flexible resources, or only allowing flexible resources to compete in the auctions if the most pressing problem regards flexibility. Albeit at a smaller scale, the combination of smart meters and real time pricing can add demand flexibility from households. The deployment of automated systems that would, for example, allow the turning on and off of homes appliances as a function of wholesale electricity prices or following 48

The production of renewable resources varies greatly due to fluctuations in the availability of sun and wind. Sometimes, there are sudden drops in renewable production that coincide with sharp increases in demand. This occurs at sunset, when solar production drops to zero while electricity demand ramps up. 49 Fossil fuel plants such as coal and gas-fired plants, Combined Heat and Power (CHP) and biomass plants are an important source of flexibility, as they can be ramped up and down within few minutes. Hydro production and pumped storage are also an important source of flexibility, but they are not available or they are not sufficiently abundant in all countries.


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the instructions of the System Operator, will strengthen the potential response of household demand thus providing a true source of flexibility. The use of the electric vehicle will also strengthen the possibilities for households to provide demand response. Even though the potential for demand response from households is yet to be seen in practice, more resources should be devoted to exploit its full potential. 8. Research and development must keep on playing a key role in the Energy Transition. The impact of regulatory policies on market structure and the incentives to innovate should be carefully assessed when designing policy. In the power sector, the energy transition implies a shift to innovative and future-proof technologies. This can only be achieved if R&D allows for the discovery of new low-carbon technologies, for the improvement of existing ones, and for the reduction of their costs. Without R&D, the Energy Transition would be technologically unfeasible, or its costs would simply be too high to make it happen. Regulation has a clear impact on R&D, both directly through the provision of funds and access to capital for innovations, and indirectly through the demand pull effects provided by low carbon policies. Indeed, expectations about future demand for renewable technologies or energy efficient investments increase the incentives to engage in R&D efforts by enlarging the payoff to successful innovators. Carbon pricing also has important effects on R&D efforts: as it makes electricity generation from unabated fossil fuel plants costly, it provides incentives to reduce those plants’ emissions rates through retrofitting, through the use of scrubbers, or through improved carbon capture and storage. All this suggests that those policies that directly or indirectly affect R&D incentives should be assessed and strengthened where needed. In this sense, there is a clear case for strengthening the carbon price signal. The positive experiences regarding R&D in low carbon technologies should not stop policy from moving forward in this area. While it is true that the initial phase of the energy transition has been conducive to innovation, it is not guaranteed that the future phases will remain so. As the energy transition evolves, the market structure and the business models will change, and so will the regulatory options. Their implications on innovation incentives are still unclear. For instance, if too much focus is put on a technology neutral approach, what will be the impact on innovation efforts in the less mature technologies? Similarly, if auctions are used to allocate new renewable projects, will this create barriers of entry for the small innovative start-ups and thus dampen their innovative potential? In sum, the new regulatory environment might create new challenges with regard to innovation. For the Energy Transition to keep on delivering break-through innovations it is paramount to make sure that resources and incentives are still in place to make innovation possible.


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9. Regulatory stability is crucial for the Energy Transition. This is not in contradiction with the need to have rules that evolve during the transition period as long as the course of changes is clearly set and announced in advance. Low carbon investments are capital intensive and thus require regulatory stability. Otherwise the fear of hold-up will deter investments from taking place, or will at least add risk premia to the costs of investments. Some regulatory instruments provide more perceived regulatory stability than others, and so they should be given priority. For instance, FiTs have been shown to be too sensitive to political intervention. In some countries, FiTs for renewables have been decreased in a retroactive manner (e.g. Spain) or ROCs have been stopped earlier than expected (e.g. the UK), undermining investors’ confidence. The effects spread across EU borders as investors perceive the EC is compliant with those retroactive measures. In contrast, regulatory uncertainty is much lower if payments to renewables are implemented through CfDs given that these provide stronger contractual rights and obligations to both parties. Indeed, this has been one of the reasons why the UK set up a CfD Counterparty as a Government owned limited-liability company. It is also crucial to give certainty to investors by defining a clear course well beyond 2020. This can be achieved through interim targets and multiannual plans on the amount of renewable capacity and back-up that is going to be installed. Some degree of flexibility should be left, as the regulator might want to adjust the plans to the evolution of costs and demand. On the contrary, the use of instruments that add regulatory uncertainty should be avoided. For instance, the EU is currently investigating whether the support schemes for renewables in some EU member states constitute incompatible State Aid. It makes sense that the EC reviews payment schemes ex-ante, before they are put in place. However, ex-post assessments create regulatory uncertainty thus adding further costs to the Energy Transition.

1.6 Concluding Remarks The regulatory experiences in Germany, the UK and France provide relevant lessons for the Energy Transition in Europe, and elsewhere. The goal is challenging, but the rewards can be large. First and foremost, the transition to a low carbon economy is a necessary condition to avoid dangerous climate change. But the benefits will also go beyond those that are purely environmental, as the deep transformations embodied in the Energy Transition offer opportunities for growth in innovation-intensive and high value-added activities. The power sector is a cornerstone of the Energy Transition given its unique potential to incorporate low carbon energy resources into the whole economy. However, to facilitate the Energy Transition in the power sector, the current electricity market arrangements have to be redesigned. Which revenue streams would the current market arrangements deliver when low carbon assets – with very low marginal costs – cover demand during an increasing number of hours? How will environmental externalities be addressed in the power market when carbon prices will no longer 151006_CERREStudy_EnergyTransition_Final

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be passed through to electricity prices? What kind of competition is probable in these circumstances? If prices in wholesale markets remain low, what would be the impact on energy efficiency and how could it be enhanced? And will be the incentives to invest in back-up capacity that will rarely be used, be preserved? Back in 2010, the diagnosis underlying the UK Electricity Market Reform was clear: “the unprecedented combination of the global financial crisis, tough environmental targets, increasing gas import dependency and the closure of ageing power stations has combined to cast reasonable doubt over whether the current energy arrangements will deliver secure and sustainable energy supplies.” Despite differences across countries, this statement applies broadly beyond the UK. Some of the reforms implemented in Germany, the UK and France pave the way towards sustainable, secure and affordable energy supplies. Their experience makes us believe that a future-proof electricity market will have to rest on three pillars: • • •

Competition in the market should be progressively replaced by competition for the market, i.e., through capacity tenders run by (or on behalf) of regulators; Long-term Contracts for Differences for renewables and for back-up capacity, referenced to the spot energy market price, should be used to de-risk investments, and A liquid wholesale energy market should be preserved.

The road ahead is not straight. Ongoing efforts will have to be devoted to identifying the least cost means of avoiding climate change, and the contribution of the power sector towards this end.


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3. Case Study 1: The Energy Transition in Germany, by Felix Christian Matthes 3.1 History, objectives and targets of the energy transition in Germany The energy and the electricity systems have been subject to a wide variety of changes during the last hundred years. In contrast to this more or less steady change, the energy transition can be understood as a politically driven process of structural changes in the energy system. The special quality of the energy transition results from the combination of political drivers and structural change. In the history of the (German) energy system there have been strong political interventions (e.g. the support of the coal industry, phase-in of nuclear power) and essentially market-driven structural changes (e.g. the phase-in of long-distance electricity transmission and its implication for the patterns of power generation) but they have rarely occurred in combination. In this sense energy transition has been a part of the German energy debate since 1980 when ÖkoInstitut published its book ‘Energiewende: Growth and Prosperity without Oil and Uranium’ (Krause et al. 1980). It constituted a minority position in the energy policy discourse of the time but quickly emerged as an essential element of the debate. This was especially true after the policy-driven shift from an oil and nuclear-based system towards a system characterised by energy efficiency, renewable energy and domestic coal (at this time) found its way into the energy policy pathways drafted by two study commissions of the German Bundestag (BT 1980, 1983) on nuclear policy. The aim of these two studies was to determine policy alternatives and to break through the extremely polarised nuclear debate in Germany at the time. The concept of the Energiewende was adjusted in the late 1980s after climate change emerged as a new topic on the German energy and environmental policy agenda, again catalysed by two study commissions of the German Bundestag (BT 1990a, 1994). The new paradigm of energy transition as a structural change of the energy system to decrease greenhouse gas emissions and phase out nuclear power, by shifting the basis of the system towards one of energy efficiency and a major rollout of renewable energies partly found its way into German energy and climate policy. The German government set a target for the reduction of carbon dioxide emissions (25% by 2005 compared to 1987 levels) for the first time on 13th June 1990. It adjusted this target to a range from 25% to 30% after the reunification of Germany (reflecting the large emission abatement potentials in the former East Germany) with a new decision on 7th November 1990 (BReg 1992). It then fixed the upper bound of this range by shifting the base year in 1995 to 1990 (BReg 1997). These medium-term emission reduction targets were complemented by slight changes in nuclear policy. The nuclear reactors in Eastern Germany were shut down immediately after German reunification in 1990. In addition, a major revision of the German Atomic Energy Act was introduced in 1994, which effectively banned the commissioning of new nuclear power plants (Matthes 2000). 151006_CERREStudy_EnergyTransition_Final

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During the 1990s, German policy and society reached, relatively quickly, a consensus on mediumterm greenhouse gas emission reduction targets50 and climate policies on energy efficiency and renewable energies (BReg 1994, 1997, 2000a). However, nuclear policy has remained a key controversy in energy and climate policy. Several attempts to find a cross-party compromise on the future of the nuclear power plant fleet in Germany failed in 1993 and 1995 (Matthes 2000, Barthe 2001). A new period of energy transition policies began when the coalition of Social Democrats (Sozialdemokratische Partei Deutschlands – SPD) and the Greens (Bündnis 90/Die Grünen) took office in 1998 and ended a phase of 16 years in which the federal government was run by a coalition of Conservatives (Christlich Demokratische Union Deutschlands/Christlich-Soziale Union Deutschlands – CDU/CSU) and Liberals (Freie Demokratische Partei Deutschlands – FDP). For the first time the climate policy program of the German federal government indicated partial targets (renewable energy, energy and resource efficiency) for the period up to 2020 (BReg 2005). In parallel, a study commission of the German Bundestag explored ambitious, longer term greenhouse gas emissions reduction targets of up to 80% by 2050 (BT 2002). The Social Democrat-Green government negotiated an agreement with the electric utilities which run nuclear power stations in 2000 (BReg 2000b), which was translated into law during 2001 and entered into force in the beginning of 2002. According to this new nuclear power legislation, the lifetime of nuclear power plants was limited to 32 years of operation, including some flexibility to transfer production quotas from older to more modern plants. The legally binding phase-out of nuclear power generation for the German power system was planned to be completed by the year 2025. The Social Democrat-Green coalition lost its majority in the elections of 2005. The new government, formed by conservatives and social democrats (Grand Coalition), initiated a comprehensive energy and climate policy package – the Integrated Energy and Climate Programme (Integriertes Energieund Klimaprogramm – IEKP) in 2007 (BReg 2007, BMWi/BMU 2007). This programme included for the first time – alongside a list of 14 key energy and climate policy instruments – a firm commitment to a greenhouse gas emission reduction target of 40% below 1990 levels, if the European Union set a greenhouse gas emission reduction target of 30% by 2020 and other countries agreed to ambitious emission reduction targets (BReg 2007, BMWi/BMU 2007). The nuclear issues remained controversial in the Grand Coalition and the status quo of the nuclear phase-out trajectory set in 2000/2002 was maintained during the legislative term from 2005 to 2009. After the end of the Grand Coalition in 2009, the new coalition of conservatives and liberals focused energy policy on the revision of the nuclear phase-out legislation from 2000/2002. Given the strong 50

The German national greenhouse gas emission reduction target was adjusted to 21% below 1990 levels after the Kyoto Protocol of the United Nations Framework Convention on Climate Change (UNFCCC) was signed in 1997.


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controversies, even within the ruling parties, the lifetime extension of the German nuclear power fleet was embedded in a broader energy and climate policy package – the Energy Concept 2010 (BMWi/BMU 2010): •

The nuclear phase-out trajectory of 2000/2002 was extended by 8 years for the older reactors and by 12 years for the newer reactors. Greenhouse gas emission targets were set for 2020 (40%, now unconditional), 2030 (55%) and 2050 (80% to 95% below 1990 levels). Ambitious targets for energy efficiency and the roll-out of renewable energy sources were defined for different energy sectors, including the power sector.

• •

The shift towards long-term greenhouse gas emission reduction targets, which essentially embody the more or less full decarbonisation of the energy system, was not a stand-alone process in Germany. At the same time, other member states of the European Union, as well as the European Commission, worked, at different levels of intensity, on long-term decarbonisation targets and trajectories (e.g. EC 2011a+b). Table 1: General and sectoral targets for the German energy sector according to the Energy Concept 2010 and the Energiewende decision in 2011 Targets: Energy Concept 2010 and … GHG emissions

Renewable Energies Gross final consumption

Power generation

… 2011

Energy efficiency Primary energy

Space heating

Final Energy

Power consumption

Nuclear power

2011

-41%

2015

-47%

2917

-54%

2019

-60%

2020

-40%

18%

35%

-20%

-20%

-10%

-10%

2021

-80%

2022

-100%

2030

-55%

30%

50%

2040

-70%

45%

65%

2050

-80 to -95%

60%

80%

-50%

-80%

-40%

-25%

Base year

1990

-

-

2008

2008

2005

2008

2010

Source: German Federal Ministry for the Environment, Nature Conservation and Reactor Safety

After the Fukushima disaster in March 2011, the German government issued a moratorium for the operation of the older reactors and commissioned analysis from the Reactor Safety Commission and a newly established Ethics Commission. After both bodies presented their results on the nuclear phase-out (RSK 2011, Ethics Commission 2011), the government elaborated a revision of the Atomic Energy Act which entered into force in August 2011. This act reverses the nuclear plant


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lifetime extension of 2010 and slightly accelerates the original phase-out trajectory set up in 2000/2002. The legally binding shutdown of the last German nuclear reactors was now scheduled for the end of 2022 (BMU 2011) and was supported by a vast majority in the final voting of the German Bundestag on the respective revision of the Atomic Energy Act on 30th June 2011. All other elements of the 2010 Energy and Climate Policy Package remained unchanged after the Uturn on German nuclear policy. Consequently, the new framework of energy and climate policy in Germany was based on ambitious greenhouse gas emission reduction targets equivalent to a full decarbonisation of the economy by 2050 and the transition to an energy system in which energy supply is almost fully based on renewable energies (Table 1). The term ‘Energiewende’, which first arose in 1980 within the scope of a minority position in the German energy policy debate, was adopted as the official headline of the new German energy paradigm in 2011. The German approach to the political decisions on a long-term energy transition to a decarbonised energy system has a number of specifics. Among these is the strong political link between ambitious emissions reduction and renewable energy rollout on the one hand and the phase-out of nuclear power on the other hand. Although the Energiewende framework was set as an economy-wide programme with a broad range of targets, sub-targets and policies for at least all sectors, the power sector has always been at the centre of the debates and political action. This is partly because the heavily coal-based German power sector contributes the major share of German greenhouse gas emissions. However, it is also because this sector is primarily linked to the nuclear controversies and is, at the same time, where the potential of renewables as alternatives to nuclear and carbon-intensive power generation became first and most strongly visible for the political process. On the long political road to the Energiewende decisions of 2010 (long-term decarbonisation targets) and 2011 (ultimate phase-out of nuclear energy), a huge body of analysis and modelling built up on the different policy goals as well as on the wide range of implemented and new policy instruments. All key decisions of the German government in 1990, 1994, 1997, 2000, 2007, 2010 and 2011 were complemented by a wide range of analytical work commissioned by the government and the parliament, in addition to other analysis provided or commissioned by different stakeholders of the process.51 Irrespective of the differences in the analysis and views presented in these studies, the vast majority of analysis stated that the most significant challenges of the energy transition and its targets would result not from technical feasibilities, macroeconomic

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Altner et al. (1995), BET et al. (2011), BT (1990a+b, 1994, 2002), Consentec/IWES (2013), DEWI et al. (2005), DIW et al. (1997, 1999), dena (2012), DLR et al. (2004, 2009, 2010, 2012), Enervis (2014), EWI et al. (2010), FENES et al. (2014), FhG-ISI et al. (1997, 2008), IWES (2009), Nitsch et al. (2007), Öko-Institut (1990, 1991, 1996, 2000), Öko-Institut et al. (2008a+b, 2010, 2013, 2014), Prognos et al (1995, 1999, 2001, 2005, 2006, 2007, 2009, 2010, 2011, 2014), Prognos/IAEW (2014), r2b/EEFA (2010), r2b (2011), SRU (2011), UBA (2010).


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costs, affordability in general or security of supply issues, but from the appropriate regulatory and market arrangements as well as distributional issues between different segments of society. Explicit climate policy and energy policy with major impacts on greenhouse gas emissions or on the transition of the energy sector in Germany have a comparatively long history, covering a quarter of a century. A broad range of achievements and progress have resulted from comparatively longlasting policies but also the settlement of certain policy traditions. The wide coverage of polices and the increasing wealth of significant analyses, as well as the broad involvement of stakeholders over a comparatively long time of policy formulation and policy implementation, also have major, and very different implications, for the capabilities of climate and energy policies and are probably among the particularities of the German Energiewende. On the one hand, climate and Energiewende policy receives continuously broad public support in German society (BDEW 2014). On the other hand, public policy is confronted not only with ‘old vested interests’ (the losers of the energy transition, essentially the fossil fuel industry and a part of the energy utilities), but also with ‘new vested interests’ (the winners of the first phase of energy transition, e.g. farmers, new energy industries and developers, as well as a share of the energy utilities). It also needs to be highlighted that the target-driven energy and climate policy of Germany was increasingly embedded in, or interacted with, the respective European activities, at least for the time horizon towards 2020. The European energy and climate package of 2008 played a key role in this respect. It sets legally binding targets for greenhouse gas emissions and the use of renewable energy sources as well as indicative targets for energy efficiency. Even if the German national targets were more ambitious, the setting of legally binding targets at EU level has stabilised the German target-driven policy approach, especially if the special circumstances of German reunification are taken into account. It should, however, also be considered that German climate and energy policy has been significantly influenced by, and interacted with, the rules of the European Union beyond climate policy in its narrow sense: •

The liberalisation of the electricity and gas market with the three internal market packages of the European Union (EU 1996, 2003, 2009) constantly faced strong resistance from different German governments at the time, which enabled at least a slowdown of the structural changes but did not ultimately succeed in blocking them (unbundling of generation, transmission and distribution networks, set-up of energy market regulators);

•

The European rules on state aid have long been a topic of controversy between Germany and different EU institutions but only emerged as a key issue of German policy making after the European Commission strongly criticised the privileges of the industrial sectors under the German Renewable Energy Sources Act in 2014 and forced Germany to undertake a fundamental revision of its remuneration scheme for renewables which complies with the new guidelines on state aid (EC 2014).


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The integration of German climate and energy policy is also relevant for major failures of European policies. In particular the deep crises of the European Union Emissions Trading System (EU ETS), after huge surpluses arose in the system from 2009 onwards, significantly interfered with German energy and climate policies and compliance with the respective national targets. This crisis of the EU ETS led to a situation in which the significant roll-out of renewable energies in the German power sector was not complemented by comparable emission reductions. This was because carbon-intensive power generators were not given, in the framework of extremely low CO2 prices, an incentive to reduce emissions, and increased exports to neighbouring countries led to a stagnation of emission reductions in the German power sector. The German policy on energy transition in its different dimensions (emission abatement, nuclear phase-out, roll-out of renewables) goes back further than the decisions of 2010 and 2011. A thought experiment may, however, illustrate the real essence of these decisions. If the years 2010 and 2011 were excluded from history, this experiment shows that the effects of the Energiewende decision in 2010 and 2011 will primarily materialise beyond 2020. The nuclear phase-out has been legally binding since 2002 onwards and the roll-out of renewables up to 2020 is based on legal obligations to comply with the legal framework of the 2008 Energy and Climate Package of the European Union (EC 2008, CEU 2009). Based on a longer history and tradition of climate and energy policy, the key difference made by the Energiewende decisions in 2010 and 2011 is that these policies shifted the perspective from the short- and medium-term (2020) to the clear long-term with strategic goals and objectives (2050). This new framework helps to ensure consistency of goals and policies. It also triggers the need for approaches that can address uncertainties and innovation needs, as well as substitution, modernisation and policy cycles.

3.2 Main policies and regulatory instruments in the power sector 3.2.1 Introduction The power sector made up approximately 38% of the total carbon dioxide (CO2) emissions and approximately 44% of all greenhouse gas emissions (CO2, methane – CH4, nitrous oxide N2O, HFs, PFCs and sulphur hexafluoride – SF6) in 2014. It is the largest single source of greenhouse gas emissions and as a result a key area of climate action. Given the fact that the existing emission reduction targets effectively lead to a nearly full decarbonisation of electricity, and nuclear and CO2 capture and storage (CCS) have been rejected as acceptable decarbonisation options52, the transition of the power sector needs to be based on an highly efficient use of electricity, the shift to

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In the case of CCS, this applies at least for the power sector. It is still questionable whether the ambitious long-term emission reduction targets (80% to 95% by 2050 compared to 1990 levels) can be met without using CCS for industrial sectors like iron and steel or cement (Prognos et al. 2009, Öko-Institut et al. 2014).


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high shares of renewable energies and a larger role for less carbon-intensive generation options for the transitional period. Figure 1: Historical and projected structure of power generation and phases of electricity policy in Germany, 1950-2050 1.000 Nuclear Policy

Breakthrough

Coal Policy

Mandatory use of domestic coal

Stagnation

Other renewables

Phase-out

900 Shift to imported hard coal & hard coal decline

Decline & phase-out of hard coal and lignite

Biomass

800 Take-off & breakthrough

TWh

Renewables Policy

Stabilized growth

Solar

Main source of electricity

700

Wind

600

Hydro

500

Other fossil Natural gas

400

Hard coal

300

Lignite 200 Nuclear 100

* 1950-1954: Western Germany only

0 1950*

1960

1970

1980

1990

2000

2010

2020

2030

2040

2050

Source: Statistical Office of the German Coal Industries, Öko-Institut

Figure 1 shows the policy targets for the electricity sector and respective projections in a historical context: •

•

•

Following a 30-year period of rise and stagnation, nuclear power has clearly been in a period of decline since 2000, driven by political decisions which will not, with a very high probability, be reversed in the upcoming seven years. Power generation from renewable energy sources have shown steep, policy-driven growth since the early 1990s, which led to low production costs at least for solar PV and onshore wind from 2012. The major revision of the Renewable Energy Sources Act of 2014 marks the transition to a stabilised growth phase. After 2030 renewables are estimated to account for more than half of electricity generation. Electricity generation from coal power has been subject to regulatory interventions for many years. In the case of hard coal the use of domestic coal has been mandatory since 1973 or was heavily subsidised. After the phase-out of subsidies for domestic hard coal in 2018, the power generation from hard coal will be based on imported coal but continue to shrink due to the roll-out of power generation from renewables. The lignite-based power generation, with very low short-term marginal costs (in the absence of a significant


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•

carbon price), has recently been kept at comparatively high levels. However, it will face the challenge of carbon pricing in the framework of the EU ETS and/or national measures for the decarbonisation of the power sector, given the dominant share of emissions from lignite in the total power sector emissions of Germany. Natural gas has never been subject to explicit power sector policies in Germany, apart from specific support for combined heat and power (CHP) production, which makes up the major share of natural gas-based power generation. Given the challenging economic framework in the continental European power markets for the foreseeable future (relatively high spread between natural gas and coal prices, low CO2 prices and an incumbent fleet of coal-fired plants with low short-term marginal costs), the role of gasfired power generation will depend on the policy framework for CHP, at least for the next one or two decades.

Most of the recent analysis assumes decreasing electricity consumption from traditional appliances (Prognos et al. 2014, Öko-Institut et al. 2014), mainly as a result of a shrinking population and the increasing penetration of highly efficient electric appliances if no major rebound effects are assumed. If effective decarbonisation policies for the transport and the heat sectors are put in place, a net growth of electricity consumption could result for the period beyond 2030 (Öko-Institut et al. 2014). Against this background, the regulatory framework and/or the market arrangements for renewable energies, CHP and the efficient use of electricity, the phase-out of nuclear power, the decarbonisation of the remaining fossil fleet as well as the overarching design of the future electricity market need to be seen as the key pillars of the energy transition for the German electricity sector.

3.2.2 The remuneration scheme for power generation from renewable energy sources The introduction of a comprehensive remuneration scheme for electricity generation from renewable energy sources was one of the early and far-reaching climate policy activities in Germany which had a strong, technology-specific focus. The general approach has not been changed in the last 25 years but the instrument has nevertheless been subject to many changes, including significant structural ones from 2012 onwards. The first version of the remuneration scheme for renewable electricity generators was introduced with the German Electricity Feed-in Act (Stromeinspeisungsgesetz – StrEG) in December 1990. Electricity suppliers were obliged to purchase electricity from renewable energy sources at a fixed tariff and were allowed to bill the costs from the feed-in tariff to their customers. Electric utilities were not allowed to benefit from this scheme; the tariff was differentiated by three groups which received at least 75% (hydro power electricity from landfill and sewage gases), at least 90% (wind


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and solar power) or at least 65% (other renewables) of the average price for deliveries to end consumers. The Electricity Feed-in Act was complemented by a series of technology-specific incentive programmes. A comprehensive reform of the feed-in tariff scheme was enacted by the German Renewable Energy Sources Act in April 2000 (Erneuerbare-Energien-Gesetz – EEG 2000). The feed-in tariffs were determined in a much more technology-specific way and the tariffs for solar PV in particular were increased significantly. Electric utilities were now allowed to produce electricity under the feed-in tariff scheme. Subsequent to a more technical revision in 2004 (EEG 2004), another revision in 2009 (EEG 2009) introduced – besides a series of adjustments of specific tariffs and legal clarifications – two structural changes. On the one hand, the transmission system operators were obliged to sell the electricity from renewables at the electricity exchange to obtain more transparency in the value of the electricity and the costs of the scheme.53 On the other hand, the tariff for solar PV was shifted to a dynamic approach where the degression of the tariff was made dependent on the PV capacity expansion during the last 12 months. The period from 2009 to 2012 proved a main failure of the German Renewable Energy Sources Act. The costs for solar PV decreased significantly faster than foreseen by the tariff degression and its dynamisation mechanism and as a result an enormous boom of solar PV installations occurred. In combination with a collapse of wholesale market prices (mainly due to significant price drops in the CO2 and fuel markets and, to some extent, as a result of the increasing power generation from renewables54), the costs of the scheme for non-privileged customers increased significantly.55 In 2003, the renewables surcharge amounted to 0.42 cent per kilowatt hour (ct/kWh), increasing to 0.88 ct/kWh in 2008, to 1.31 ct/kWh in 2009, 2.05 ct/kWh in 2011 and 3.53 ct/kWh in 2012. This caused hectic revisions of the Renewable Energy Sources Act in June 2011 (EEG 2012a) and June 2012 (EEG 2012b), without being able to break the dynamics of the surcharge. 53

The marketing of renewable electricity and the calculation of difference costs between the payments to the operators and the market value had previously been left to the network operators who added system service charges and other adders to the costs of the scheme, which led to a wide range of complaints against these practices. 54 Whereas the price of emission allowances in the EU ETS clearly dominates the wholesale price trends, the impact of fuel prices and the increasing generation from renewable energy sources on the wholesale power prices differs for the spot market and the different futures markets for base and peak products (Cludius et al. 2014, Kallabis et al. 2015, Matthes 2015). 55 A broad range of industrial consumers was and is exempted from the renewables surcharge. These exemptions depend on the hypothetical costs that these industrial consumers would have to bear without these exemptions. This mechanism leads to significant repercussions: The industrial privileges decrease the basis for the surcharges and increase the surcharges. This led to higher hypothetical costs and more industrial consumers were exempted, which resulted in a further shrinking of the base for the surcharge payments, leading again to higher surcharges, etc.


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This increasing level of the renewables surcharge and the dynamics caused by the growing privileges for industrial customers56 led to a highly controversial debate on the reform of the remuneration scheme. This debate escalated after the European Commission intervened and declared that the industrial privileges were not consistent with the state aid provisions of the EU. Although the German government took the legal position that the scheme was not subject to state aid supervision, it faced the challenge that they could no longer guarantee the industrial privileges under the emerging legal uncertainties. Against this background, the German government negotiated with the European Commission on the guidelines for state aid on environmental protection and energy for 2014 to 2020 (EC 2014). It elaborated and gave notification of a major revision of the German Renewable Energy Sources Act (EEG 2014) that is in line with the state aid guidelines. This revision introduced a series of structural changes: •

•

• • •

•

Firstly, almost all new installations have to market their electricity directly and receive a dynamic premium, which is calculated as the difference between a technology-specific strike price and the average wholesale market price. Secondly, roll-out corridors were set for electricity from wind (2,400-2,600 MW annually), solar PV (2,400-2,600 MW annually) and biomass (100 MW annually). The technologyspecific strike prices are subject to adjustment if the capacity additions fall outside these corridors. Thirdly, the corridor for power generation from biomass was set very restrictively, essentially almost ending the expansion of biomass-based power generation. Fourthly, tenders for the strike prices of the variable premium model were to be introduced in stages by 2017. Fifthly, the whole model of industrial privileges regarding the obligation to contribute to the renewable surcharge was re-organised to make it structurally compliant with the new state aid guidelines, which did not however lead to significantly lower levels of exemptions for the industry under the EEG 2014. Sixthly, the incentives for the grid parity-driven rush to self-generation and indirect transfers were significantly decreased by introducing an obligation to carry a share of the renewable surcharge also for self-consumption of electricity.57

56

Industrial electricity consumers were allowed to apply for exemptions if the total costs of the renewables surcharge at the standard rate exceed certain thresholds. The increasing level of the surcharge expanded the range of exemptions, which increased the surcharge due to the shrinking base for the surcharge. 57 The relatively high retail prices for electricity and the significant shares of network access fees and surcharges in the prices attracted a lot self-generation from 2010 onwards when many decentralised generation options reached grid parity in Germany and an erosion of the financial basis for networks and the different schemes (renewables, CHP, electricity tax, concession fees, etc.) and the respective indirect transfers became significant. According to EEG 2014 self-generators with renewable or CHP installations


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Although on several occasions fundamental alternatives to the Renewable Energy Sources Act (e.g. quota models) were heavily promoted by certain stakeholders (RWI 2012, Acatech 2012), these attempts were never able to reach beyond a (weak) minority position in the debate. The promises of these alternative models with regard to efficiency gains and lowering costs for consumers were too vague or were questioned for good reason. In addition, the loss of investment certainty was perceived as far too risky from the perspective of a broad range of players in the field of renewable power generation as well as the broader public and the policy arena. As a result, fixed tariffs for electricity generation from renewable energy sources were maintained over a phase of about 25 years of successful roll-out of renewable power in the German energy system. However, the changes introduced by EEG 2014 as well as the emerging levels of renewable power generation (Figure 2 and Figure 3) provide a strong indication that further adjustments of the remuneration scheme for renewables will be needed soon: •

•

The legal framework of the recent state aid guidelines requires the shift to tendering procedures from 2017 onwards. This will end the phase of administratively fixed tariffs (or the equivalent strike prices within the model of variable premiums).58 Even if these state aid guidelines did not apply, administratively fixed tariffs for significant shares in the total electricity generation (soon more than a third in Germany) would no longer fit in the framework of the liberalised market model of the electricity sector in Europe. Beyond a share of 30% of renewable power generation, mainly from variable sources like solar PV and wind, renewables will deliver the full load in an increasing number of hours of the year. If the remuneration scheme for renewables continues to be based on premiums for electricity generation this will cause increasingly negative prices in the wholesale market, which will not result from technical inflexibilities of conventional power plants but from the regulatory framework for renewables.59 This topic will have a major impact on investment certainty, which has been one of the most significant benefits of the existing model, given the fact that the state aid guidelines exclude the payment of premiums if the periods of negative prices in the wholesale markets reach durations of 6 or more hours.

larger than 10 kW must pay a 40% share of the renewables surcharge for self-consumed electricity from 2017 onwards, all other self-generators are obliged to pay the full surcharge. 58 The German government continues to take legal action against the position of the European Commission that the German feed-in legislation is subject to state aid control. However, the duration of these legal processes of clarification will lead to a situation in which the design of the German remuneration scheme for renewables needs to comply with the state aid guidelines at least for the next few years. 59 If negative prices occur in the wholesale market, renewable generators will only start to shut down production if the level of negative prices is higher than the premium on electricity generation which the generators are to lose if they stop producing.


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Figure 2: Historical and projected power generation from renewable power sources according to the German Energy Concept 2010/2011, 1990-2050 700 Legal commitment (EU)

Historical data

National targets 100%

600 Targets of the Energy Concept 2010/2011

500

80% Upper and lower bound of corridor as defined in the Coalition Treaty 2013 & the Renewable Energy Act of 2014 (EEG 2014)

TWh

400

60%

300

Geothermal Landfill gas

40%

Waste (biogenic) 200

Biomass Photovoltaics 20%

Wind - offshore

100

Wind - onshore Hydro 0

0% 1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

Source: German Federal Ministry for Economic Affairs and Energy, Öko-Institut


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Figure 3: Historical and projected power generation capacities of renewable power sources according to the German Energy Concept 2010/2011, 1990-2050 350 Legal EU commitment

Historical Data

National targets 100%

300 Geothermal Expansion corridor for power generation from RES to 80-100% in 2050

Landfill gas

250

Waste (biogenic) Biomass

200

Maximum effective load coverage of the RES-based generation fleet

Photovoltaics

GW

80%

60%

Wind - offshore 150

Wind - onshore 40%

Hydro 100 Load range

20%

50

0

0% 1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

Source: German Federal Ministry for Economic Affairs and Energy, Öko-Institut

In contrast to the last few years, the cost of the remuneration scheme for renewables will probably be of less importance in the near future. The recent level of the renewables surcharge is projected to be stable for the next few years and only grow slowly afterwards. The probability of steep increases of the surcharge in the future and the related political turmoil is relatively low (ÖkoInstitut 2014a) and so the structural aspects of the remuneration schemes and the overall consistency of the regulatory framework of a liberalised electricity market will acquire major importance. This will trigger new debates on the appropriate remuneration mechanisms for renewable energies. These will need to find a new balance between the integration into the coordination mechanisms of the electricity markets and the need for a sufficient level of investment certainty for renewable energy projects and the relevant groups of investors (ÖkoInstitut 2014c).

3.2.3 The remuneration scheme for combined heat and power production Historically, combined heat and power production (CHP) has played a special role in the German electricity system. This is firstly a result of the strong role of municipal utilities in the German power industry, which often combine the production of district heat for residential, commercial and industrial customers with power generation in CHP installations. Secondly, many industrial


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enterprises in Germany use CHP for their self-generation of power and heat for thermic production process. Significant parts of the energy production in CHP plants in Germany are based on natural gas. Coalbased CHP also contributes to energy production, but less significantly. Due to this, CHP is not only widely perceived as an option for the efficient use of energy resources, but also as a significant contribution to the reduction of greenhouse gas emissions, at least in the medium-term. Furthermore, increasing investments in decentralised CHP installations have made CHP a widespread technology that receives a lot of public attention. Figure 4: Historical power generation from CHP installations by operator group and share in total net electricity generation in Germany, 2003-2013 120

24% Bio-CHP not covered by official statistics

TWh

100

20%

80

16%

60

12%

40

8%

20

4%

Decentralised CHP